fossil energy - iiasa

901

Fossil Energy

Convening Lead Authors (CLA) Eric D. Larson (Princeton University and Climate Central, USA) Zheng Li (Tsinghua University, China)

Lead Author (LA) Robert H. Williams (Princeton University, USA)

Contributing Authors (CA) Theo H. Fleisch (BP America (retired), USA) Guangjian Liu (North China Electric Power University) George L. Nicolaides (Wildcat Venture Management, USA) Xiangkun Ren (Shenhua Coal Liquefaction Research Center, China)

Review Editor Peter McCabe (Commonwealth Scientifi c and Industrial Research Organization, Australia)

12

Fossil Energy Chapter 12

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Contents

Executive Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 904

12.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 909

12.2 Fossil Energy Technologies for Power Generation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 910

12.2.1 Overview of Global Electricity Demand and Supply . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 910

12.2.2 Steam Electric Power Generation Using Pulverized Coal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 911

12.2.3 Gasifi cation-based Power Generation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 914

12.2.4 Natural Gas Combined Cycle Technology . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 919

12.2.5 Health Damage Costs of Power Plants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 921

12.3 Technological Changes at Refi neries and Opportunities for CCS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 925

12.3.1 Context . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 925

12.3.2 Refi ning Technology and Economics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 928

12.3.3 Greenhouse Gas Emissions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 929

12.3.4 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 931

12.4 Transportation Fuels from Non-petroleum Feedstocks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 931

12.4.1 Gas to Liquids . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 931

12.4.2 Direct Coal Liquefaction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 935

12.4.3 Gasifi cation-based Liquid Fuels from Coal (and/or Biomass) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 937

12.4.4 Hydrogen from Non-petroleum Feedstocks for Transportation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 944

12.5 Clean Household Fuels Derived from Non-petroleum Feedstocks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 948

12.5.1 Dimethyl Ether from Coal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 949

12.5.2 Synthetic LPG from Coal and/or Biomass . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 950

12.5.3 Co-providing Synthetic Cooking and Transport Fuels in the Context of a Carbon Mitigation Policy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 952

Chapter 12 Fossil Energy

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12.6 Coproduction of Liquid Fuels and Electricity from Non-petroleum Feedstocks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 958

12.6.1 Performance Estimates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 958

12.6.2 Cost estimates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 961

12.6.3 Coproduction Economics from the Electricity Production Perspective . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 963

12.6.4 Alternative Approaches for Low GHG-emitting Liquid Fuels Using Biomass . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 972

12.6.5 Coal/biomass Coprocessing with CCS as a Bridge to CCS for Biofuels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 975

12.6.6 Global Coal/biomass Thought Experiment for Transportation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 976

12.7 Long-term Considerations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 978

12.7.1 Low-carbon Electricity Generation Technologies in the Long-term . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 978

12.7.2 Technologies and Strategies for Low-carbon Liquid fuels in the Long-term . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 979

12.8 Strategies and Policies for Radically Transforming the Fossil Energy Landscape . . . . . . . . . . . . . . . . . . . . . . . . . . 984

12.8.1 Strategies for a Radical Transformation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 984

12.8.2 New Policies for a Radical Transformation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 986

References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 988


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Executive Summary

Analysis in Chapter 12 shows that a radical transformation of the fossil energy landscape is feasible for simultaneously meeting the multiple sustainability goals of wider access to modern energy carriers, reduced air pollution health risks, enhanced energy security, and major greenhouse gas (GHG) emissions reductions.

Fossil fuels will dominate energy use for decades to come. Two fi ndings apply to developing and industrialized countries alike. First, fossil fuels must be used judiciously − by designing energy systems for which the quality of energy supply is well matched to the quality of energy service required, and by exploiting other opportunities for realizing high effi ciencies. Second, continued use of coal and other fossil fuels in a carbon-constrained world requires that carbon capture and storage (CCS) becomes a major carbon mitigation activity.

Since developing and industrialized countries have different energy priorities, strategies for fossil energy development will be different between these regions in the short term, but must converge in the long term. The focus in developing countries should be on increasing access to modern and clean energy carriers, building new manufacturing and energy infrastructures that anticipate the evolution to low carbon energy systems, and exploiting the rapid growth in these infrastructures to facilitate introduction of the advanced energy technologies needed to meet sustainability goals. Rapidly growing economies are good theaters for innovation. In industrialized countries, where energy infrastructures are largely already in place, a high priority should be overhauling existing coal power plant sites to add additional capabilities (such as coproduction of power and fuels) and CCS. (Simply switching from coal to natural gas power generation without CCS will not achieve the ultimately needed deep carbon emission reductions.)

Analysis in Chapter 12 highlights the essential technology-related requirements for a radical transformation of the fossil energy landscape: (i) continued enhancement of unit energy conversion effi ciencies, (ii) successful commercial deployment of carbon capture and storage, (iii) co-utilization of fossil and renewable energy in the same facilities, and (iv) effi cient coproduction of multiple energy carriers at the same facilities.

Among the fossil fuel-using technologies described in this chapter, only coproduction strategies using some biomass with the fossil fuel and with CCS have characteristics such that they can simultaneously address all four of the major energy-related societal challenges identifi ed by GEA, as shown in Figure 12.1 . It is plausible that these technologies could begin to be deployed in the relatively near term (2015–2020) because nearly all of the technology components of such systems are already in commercial use. Hydrogen made from fossil fuels with CCS is an energy option in the long term, but infrastructure challenges associated with hydrogen distribution and end use (especially for mobile applications) amplify the magnitude of the fossil energy challenge and are likely to limit hydrogen as an option in the near term. Other energy options may emerge in the post-2050 timeframe, and some ideas are touched upon briefl y in this chapter.

The energy performance, cost, and GHG emissions of many of the power generation and coproduction technologies described in this chapter are summarized in Table 12.1 and Table 12.2 . (Similar metrics for hydrogen production from fossil fuels and for smaller scale coproduction systems that coprocess biomass and coal or biomass and natural gas can be found in the main body of this chapter.)

Table 12.2 includes coal-biomass coprocessing systems with CCS that provide liquid fuels and electricity via coproduction. These technologies are attractive both as repowering and repurposing options for existing coal power plant sites and for greenfi eld projects. The economics of such systems depends on the greenhouse gas emissions price and the oil price, as discussed quantitatively in this chapter.

Clear benefi ts of this coproduction approach include:

• greatly reduced carbon emissions for electricity and transportation fuels;

• enhanced energy supply security;


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• provision of transportation fuels that are less polluting in terms of conventional air pollutants than petroleum-derived fuels;

• provision of super-clean synthetic cooking fuels such as liquefi ed petroleum gas (LPG) and dimethyl ether (DME) as alternatives to cooking with biomass and coal, which is critically important for developing countries; and

• greatly reduced severe health damage costs due to particulate matter (PM 2.5 ) air pollution from conventional coal power plants.

Coprocessing biomass with coal in these systems requires half or less biomass to provide low-carbon transport fuels as required for advanced fuels made only from biomass, such as cellulosic ethanol.

Security (lower imports)

Access (clean HH fuel)

Air quality (outdoor)

Climate

NGCC

Oil refining

Coal steam power

Gasifica�on Power

Gasifica�on liquids

GTL

Natural Gas

Biomass

with ccs

Power/liquids Co - produc�on

Direct Liquefac�on

Power/liquids Co - produc�on

Oil

Coal

Figure 12.1 | Commercial or near-commercial fossil energy technologies discussed in this chapter and their suitability for addressing four major energy-related challenges. Among the listed technology options, only coproduction systems (that include coprocessing of some biomass) are capable of addressing all major challenges.


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Table 12.1 | Performance and cost estimates in US 2007 $ from this chapter for power generating technologies under US conditions. (To express costs in other-year US$, use the Chemical Engineering Plant Cost Index as shown in Figure 12.4 and discussed in text accompanying it.)

Installed cost (US$/kW e )

Capacity (MW e )

Levelized electricity cost a (US$/

MWh)

Plant inputs (MW HHV) Life cycle GHG c

kgCO 2 -eq per MWh

Coal Biomass b Natural gas

WITHOUT CO 2 capture and storage

Sub-critical pulverized coal

1598 550 62 1496 896

Super-critical pulverized coal

1625 550 61 1405 831

Coal-IGCC (GEE radiant)

1865 640 68 1673 833

Coal-IGCC (Conoco-Phillips)

1788 623 65 1586 823

Coal-IGCC (Shell) 2076 636 72 1546 787

Coal-IGCC (GEE quench)

1901 528 69 1405 833

Biomass IGCC (Carbona)

2008 317 92 699 25

NGCC (F class GT) 572 560 51 1102 421

WITH CO 2 capture and storage

Sub-critical pulverized coal

2987 550 114 2211 187

Super-critical pulverized coal

2961 546 111 2004 171

Coal-IGCC (GEE radiant)

2466 556 92 1709 138

Coal-IGCC (Conoco-Phillips)

2508 518 94 1634 162

Coal-IGCC (Shell) 2755 517 101 1616 136

Coal-IGCC (GEE quench)

2677 435 100 1405 126

Biomass IGCC (Carbona)

2779 259 129 699 –776

NGCC (F class GT) 1209 482 77 1102 110

a Assuming capacity factor of 0.85. Prices assumed (US$/GJ HHV ) for coal, biomass, and natural gas are US$2.04, US$5, and US$5.11, respectively. b As-received biomass moisture content is 15% by weight. c Includes GHG emissions associated with feedstock production and delivery to the power plant.

Coproduction also represents a promising approach for gaining early market experience with CCS, because CO 2 capture is easier in coproduction than for stand-alone power plants. In the near term, coproduction could serve as a bridge to enabling CCS as a routine activity for biomass energy, with corresponding negative greenhouse gas emissions, in the post-2030 era. Analysis in this chapter shows that this could plausibly become a major industrial activity under a carbon mitigation policy for economically poor but biomass-rich regions, where it could make clean cooking fuels widely available and affordable in the regions while making major contributions to decarbonization of the transport sector worldwide.

No technological breakthroughs are needed to get started with coproduction strategies, but there are formidable institutional hurdles created by the need to manage two disparate feedstocks (coal and biomass) and provide


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Table 12.2 | Summary of performance and cost estimates in US 2007 $ from this chapter for alternative coproduction systems. Electricity is coproduced (to greater or lesser degree) with liquid fuels in all of these systems. FTL refers to Fischer-Tropsch liquids. MTG stands for methanol-to-gasoline. (To express costs in other-year US$, use the Chemical Engineering Plant Cost Index as shown in Figure 12.4 and discussed in text accompanying it.)

Installed cost US$/(bbl eq /d) a

Capacity (bbl eq /d) a

O&M 10 6 US$/yr

Plant Inputs b Plant Outputs b GHG

Emission Index

(GHGI) d Coal

MW HHV Biomass c MW HHV

Synthetic Diesel MW LHV

Synthetic Gasoline MW LHV

Synthetic LPG

MW LHV

Electricity MW e

WITHOUT CO 2 capture and storage

Coal FTL 97,033 50,000 194 7559 9 2006 1153 404 1.71

Coal MTG 80,757 50,000 162 6549 0 2913 309 126 1.76

Coal FTL/Power

122,958 35,706 176 7559 1431 825 1260 1.31

Coal MTG/Power

126,167 32,579 164 6549 1898 202 959 1.37

Biomass FTL 160,189 4521 29 661 182 104 42 0.063

Biomass MTG

171,520 4630 32 661 270 28 32 0.066

WITH CO 2 capture and storage

Coal FTL 98,372 50,000 197 7559 2006 1153 295 0.89

Coal MTG 82,099 50,000 164 6549 2913 309 36 0.97

Coal FTL/Power

128,093 35,706 183 7559 1431 825 1058 0.70

Coal MTG/Power

132,293 32,579 172 6549 1898 202 760 0.56

Biomass FTL 162,927 4521 29 661 181 105 31 –0.95

Biomass MTG

174,131 4630 32 661 270 28 20 –1.07

C+B FTL 139,091 9845 55 804 661 395 227 53 0.029

C+B MTG 129,200 10,476 54 781 661 610 69 11 0.018

C+B FTL/Power

177,526 8036 57 1011 661 322 186 257 0.093

C+B MTG/Power

180,110 11,582 83 1651 661 675 68 292 0.089

a bbl eq /d is energy-equivalent barrels (LHV basis) per day of petroleum-derived fuels that could be replaced by the synthetic liquids. b LHV is lower heating value and HHV is higher heating value. c As-received biomass moisture content is 15% by weight. d GHGI = system wide life cycle GHG emissions for production and consumption of the energy products divided by emissions from a reference system producing the same amount

of liquid fuels and electricity. Here the reference system consists of equivalent crude oil-derived liquid fuels plus electricity from a stand-alone new supercritical pulverized coal power plant venting CO 2 . See Table 12.15 , note (c) for additional details.

simultaneously three products (liquid fuels, electricity, and CO 2 ) serving three different commodity markets. Creative public policies can help overcome these and other hurdles. Most importantly:

• Policy is urgently needed that sets a price on greenhouse gas emissions high enough to motivate CCS as a commercial activity.

• Stricter limits on air pollution are needed, especially from existing coal power plants and from indoor direct combustion sources. For the latter, policies should be designed to induce a shift, especially among the poor, from cooking by direct combustion of biomass or coal to using clean fl uid fuels. Added costs that would result from


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stricter air pollution limits can be justifi ed on the basis of the large reductions in public health damage costs that would follow.

• Incentives are urgently needed that specifi cally target integrated CCS demonstration projects at megascale. To minimize spending on such incentives, governments should aim to pursue projects from which maximum learning is derived per dollar spent. This would include multilateral fi nancial support for these demonstrations, since all countries needing CCS technologies will benefi t from these early projects if the learning is well documented and shared.

• Policies are needed that support early deployment of promising new technologies and systems at commercial scale, such as coproduction with CCS. Without incentives for fi rst-of-a-kind projects that offer major public benefi ts, promising new technologies will enter the market slowly or not at all. Incentives should include ones that encourage new inter-industry partnerships where needed. It is desirable that policy instruments specify performance goals rather than specifi c technologies, and maximize use of market forces in meeting the goals.

• CO 2 storage prospects are not well known in many countries where sorely-needed clean liquid cooking fuels could be produced from coal or biomass while storing byproduct CO 2 underground. This is especially true for many biomass-rich but coal-poor countries. Detailed assessments of CO 2 storage prospects are needed on a reservoir-by-reservoir basis in these countries. Financial support for these assessments from the international community would be appropriate.

• International collaboration is needed to speed up the needed global energy transformation, including assistance from industrialized to developing countries for technological and institutional capacity development.

• New public policies are needed to facilitate industrial collaborations between companies producing transportation fuels, electricity, and clean cooking fuels and to encourage coprocessing of coal and biomass in regions having signifi cant supplies of both (e.g., United States and China). It is desirable that policy instruments specify performance rather than technology and maximize use of market forces in meeting performance goals.


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12.1 Introduction

In 2009, the world used 11,164 million tonnes of oil equivalent (Mtoe) or 469 exajoules (EJ) of commercial energy in total, nearly 90% of which was from fossil sources (BP, 2010 ). Due to advantages in cost, techno-logical maturity and established industry and infrastructure, fossil ener-gies are very likely to remain as a major component of world energy supply for several decades (especially coal-based power generation and liquid hydrocarbon fuels for transport), even as the world increasingly transitions to renewable energy technologies. At the same time, as dis-cussed in earlier chapters, the world today faces four major challenges stemming from fossil energy use: a widespread lack of access to afford-able modern energy carriers ( Chapter 2 ), climate change ( Chapter 3 ), air pollution ( Chapter 4 ), and energy insecurity ( Chapter 5 ). Given that con-tinued use of fossil fuels is likely for at least the next several decades, how can they be used to address effectively these four challenges? This question frames the content of this chapter. Figure 12.2 shows the broad filtering criteria applied to focus the discussion in this chapter.

A technology “missing” from Figure 12.2 is combined heat and power (CHP). Large energy and environmental benefits can be achieved by replacing separate stand-alone power and heat production systems with CHP. Carbon emission reductions can be especially significant when stand-alone coal-fired systems are replaced with natural gas fired

CHP systems (Krause et al., 1994 ). We do not discuss CHP in this chapter in large part because the analysis presented on this topic in the World Energy Assessment (Williams, 2000 ) is still relevant today.

Hydrogen as a vehicle fuel is also not analyzed in this chapter. Technologies for fossil fuel conversion to hydrogen are described, but because hydrogen distribution and end-use infrastructural challenges associated with using it in vehicles likely would require at least sev-eral decades to overcome, the emphasis on transportation fuels in this chapter is on liquid fuels that can be made from hydrocarbon (fossil or biomass) resources.

In Chapter 12 , power generation technologies are discussed in Section 12.2 with an emphasis on their ability to reduce carbon emissions. Section 12.3 discusses the possibilities for carbon mitigation in con-ventional petroleum refineries. Section 12.4 discusses alternative trans-portation fuel technologies that can ease energy security tension and also help reduce carbon emissions from transportation. Section 12.5 discusses roles of non-petroleum feedstocks for production of clean household fuels that can help to address the problem of the widespread lack of access to modern energy carriers. In Section 12.6 , strategies for coproduction of electricity and fuels are discussed. These offer the prospects for comprehensive solutions to using fossil fuels efficiently, economically, and with low environmental impacts, both in retrofitting

Figure 12.2 | Technology fi lters for this chapter.


910

existing energy facilities and in new installations needed to meet grow-ing energy demands. Section 12.7 touches briefly on long-term tech-nology options. Section 12.8 steps back from technology to consider strategic and policy issues.

12.2 Fossil Energy Technologies for Power Generation

For the foreseeable future, electricity will be one of the major energy carriers used by society. The problem lies in the large amount of fossil energy (and emissions) associated with electricity generation today to meet global demands.

Fossil fuels are the predominant primary energy at present in the world, accounting for nearly 90% of commercial energy use (BP, 2010 ). They are also the dominant fuel for power generation: producing about two thirds of our electricity today and projected to provide a similar frac-tion in 2035 (IEA, 2010 ). Today, fossil fuels are the most mature and economic source for power generation. However, they also account for most local conventional pollution and global carbon dioxide emissions. The future of fossil energy power generation in a carbon-constrained world depends on a compromise between growth in electricity demand and reduction in carbon dioxide emissions.

This section focuses on comparing the energy, environmental, and eco-nomic performance of fossil energy power generation technologies including coal-steam power, integrated coal gasification combined cycle (IGCC) and natural gas combined cycle (NGCC) with and without car-bon capture and storage (CCS). The section also touches on other issues related to sustainable development, including water usage, health dam-age from environmental pollution, and co-utilization of coal with bio-mass, reflecting the intention of this section to explore alternatives for using fossil energy wisely and with lower carbon emissions.

12.2.1 Overview of Global Electricity Demand and Supply

The International Energy Agency (IEA) describes current and projected future electricity demand and supply (IEA, 2010 ). Here we cite relevant numbers from the IEA to give a general overview of fossil energy power generation.

12.2.1.1 Current Electricity Demand and Supply

Electricity is the “blood” of modern society that supports human pros-perity. Electricity demand has invariably increased along with economic growth. In 2008, world end-use energy utilization was 8423 Mtoe (354 EJ) (IEA, 2010 ), including coal, oil, natural gas, electricity, heat, biomass, and waste. Oil usage ranked first with a fraction of 42%. Electricity was second, at 17%. This indicates the importance of electricity in modern society.

In 2008, 16,814 terawatt hours (TWh) of electricity was consumed in end uses globally but with a regional imbalance. Member countries of the Organisation for Economic Co-operation and Development (OECD), with 18% of world population, 1 consumed 9244 TWh (55% of the total). Non-OECD countries, with 82% of world population, consumed 7570 TWh (45%). Per capita electricity demand in non-OECD countries was about 1300 kilowatt hours (kWh) per person, or only one sixth of that in OECD countries. Today, some 1.4 billion people still have no electric-ity supply, some 85% of them in rural areas (IEA, 2010 ). No access to electricity means not only energy deprivation, but also a lower capacity for economic growth, which has deep and long-term impacts.

The largest electricity consumption, 3814 TWh (23% of the world total) among OECD countries is by the United States. Among developing coun-tries, China has the largest electricity consumption, 2884 TWh (15% of world total). Since China has about 20% of the world’s population, per capita electricity consumption there is still lower than the world average.

The two countries also lead in power production. In 2008, the total electricity generation globally was 20,183 TWh, of which 53% was in OECD countries. The United States and China were the largest power-generating countries in OECD and in the developing world, respectively, accounting for 22% and 17% of global power production. Power gen-eration in Africa was only 621 TWh, or 3% of the global total.

Total global power generating capacity was 4719 gigawatts (GW) in 2008. The primary energy sources used for power generation by percent-age were coal (41%), oil (5%), natural gas (21%), nuclear (14%), hydro (16%), and other renewable energy (3%). The share of fossil energy power capacity (coal, oil, and gas) is 67%.

The primary energy used for power generation differs by geograph-ical region, depending on resource endowments as well as the state of economic and technological development. In general, the share of nuclear power is much higher in OECD countries (26% in 2008) than in non-OECD countries (5% in 2008). This may be due to the advantage of OECD countries in mastering nuclear technology as well as their economic power. Hydropower depends on resource availability. The share of hydropower is 40% in Latin America, for example. In coun-tries with abundant coal, coal-steam power is the low-cost choice. In China, India and the United States, respectively, coal power accounts for about 79%, 69%, and 49% of power generation. Natural gas is the best feedstock among fossil fuels for power generation in the sense of energy efficiency and environmental pollution. However, its application depends either on resources or on economic power. This resource is available in Russia, for example, with 48% of its power from natural gas, and in the Middle East, with 58%. The impact of economic power is evident in the use of natural gas by OECD countries, with 22% of their power from natural gas, in contrast to non-OECD Asia, with 10%.

1 The total population of OECD countries was 1.18 billion in 2007. The total popula-tion in the world was 6.6 billion.


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In China, because natural gas is rare and valuable, only 1% of power generation is from natural gas.

Globally, power generation is one of the major sources of CO 2 emis-sions, accounting for 11.9 gigatonne (Gt) in 2008, or 41% of the world’s total fossil fuel CO 2 emissions. In many developing countries, however, conventional environmental pollution is considered a more urgent issue than CO 2 emissions because of the damage to the envi-ronment and human health it is causing today. China’s emissions of sulfur oxides and nitrogen oxides (SO x and NO x ) and dust were 25.9 million tonnes (Mt), 15.2 Mt, and 10.9 Mt in 2006. Contributions from power generation were 45%, 41%, and 29%, respectively (State Environmental Protection Administration of China, 2007 ). India’s emissions of sulfur dioxide (SO 2 ), NO x , and particulate matter less than 2.5 micrometers in diameter (PM 2.5 ) were 6.7 Mt, 4.1 Mt, and 4.7 Mt in 2005. The reduction of conventional pollutants is imperative and urgent for both countries.

Public health costs of air pollution (especially SO x , NO x , and PM) from fossil fuel power generation are discussed later in this section. A large amount of new power generation infrastructure is being established daily in developing countries, especially in countries such as China and India that are undergoing rapid industrialization and urbanization. It is of great importance for the sustainable development of societies like China’s and India’s to find ways to simultaneously address conventional pollutant emissions and carbon emissions.

12.2.1.2 Future Electricity Demand and Supply Expansion

In the “current policies” scenario of the World Energy Outlook 2010 (IEA, 2010 ), world electricity demand is projected to increase 95% from 2008 to 2035, reaching 32,919 TWh. Every region of the world is pro-jected to increase, though at different rates. The increase in non-OECD consumption accounts for 82% of the total projected global increase. Even in this case, annual per capita electricity consumption in non-OECD countries only reaches 4600 kWh, about half the average for OECD countries (9200 kWh). In Africa, annual per capita electricity consump-tion is projected to increase only modestly, to 700 kWh per person.

In this scenario, which assumes a future world with essentially no price on carbon emissions, China is projected to have the largest increase in both total electricity consumption and annual per capita consump-tion among developing countries. China’s electricity consumption is projected to be 9420 TWh in 2035, surpassing the United States as the world’s largest consumer. The large projected increase in annual per capita consumption in China brings it to 6400 kWh, a level slightly under 70% of the OECD average.

In the current policies scenario, world power production is projected to increase by 90% from 2008 to 2035, reaching 38,423 TWh. Likewise, total installed power generation capacity is projected to be 8875 GW,

representing an 88% increase compared to 2008. The share of electricity by source is projected to change only modestly from 2008 to 2035: coal from 41% to 43%, oil from 5% to 2%, natural gas from 22% to 21%, nuclear from 14% to 11%, hydropower from 16% to 13%, and renew-able energy (other than hydro) from 3% to 10%.

Correspondingly, global CO 2 emissions from fossil fuels are projected to increase by 46%, going from 29,260 Mt in 2008 to 42,589 Mt in 2035. CO 2 emissions from power generation are projected to increase by 59% to 18,931 Mt. Together, China and India account for 75% of the total projected global increase in power sector CO 2 emissions from 2008 to 2035. Power sector emissions in 2035 are projected to be 7130 Mt in China and 2068 Mt in India. Overall, emissions from coal power top the global list. Emissions from coal power are projected to be 14,403 Mt, accounting for 76% of all power generation emissions and one third of total global fossil fuel emissions.

12.2.2 Steam Electric Power Generation Using Pulverized Coal

12.2.2.1 Process description

At present, coal-steam power based on the Rankine cycle is the most commonly applied power generation technology worldwide. Utility coal boilers are generally divided into pulverized coal (PC) and circulating fluidized bed (CFB) units, which describes the method of combustion in the furnace. Since it is the predominant form of coal-steam power generation, PC combustion is the main focus of the discussion here. Some basic information about CFB is provided in Box 12.1 , including coal-biomass cofiring, an option that is attracting increased attention with the drive toward greater use of renewable energy.

Figure 12.3 shows the process of a typical pulverized coal combustion power plant. Major equipment includes the boiler, steam turbine, and electric generator. The system can be simply described by following the fluid loops inside the process.

Water and steam loop: This is the working fluid in the power plant. •Cold water from the condenser is boiled and converted into super-heated steam and sent to the steam turbine where it expands to generate mechanical rotating power. This mechanical power drives an electric generator to generate electricity, which is then trans-formed into high voltage and sent into the electricity grid. The steam exhausted from the turbine is cooled in the condenser and then sent back to the boiler to repeat the cycle.

Air-flue gas loop: Air from the atmosphere is pumped into the boiler •furnace to provide combustion air to burn the coal, the hot combus-tion products from which heat the water-steam loop. After releasing heat, the flue gas first goes through a selective catalytic reduction unit to get rid of NO x , then to an electrostatic precipitator to reduce


912

Figure 12.3 | Pulverized coal combustion power plant. Source: Termuehlen and Empsperger, 2003 .

Box 12.1 | Other Combustion Options

Circulating fl uidized bed (CFB) combustion power generation technology was originally developed as a low-cost approach to sulfur control and to facilitate the use of low-quality coals. Currently, the main objective is to facilitate the use of low-quality coals.

In fl uidized bed coal combustion, coal is crushed into pieces smaller than 10 mm and mixed with a large amount of fl uidized bed material to burn inside the furnace. The typical bed temperature is 850°C, an appropriate level to minimize formation of thermal NO x . Limestone is fed into the furnace along with coal in order to absorb sulfur dioxide formed during combustion. Up to 90% or more of the sulfur can be removed by simply adding limestone. This makes CFB a favorite lower-cost clean coal technology in developing countries. In China, for example, more than 2000 CFB boilers are in operation and the largest unit capacity is 300 MW. Units up to 600 MW (supercritical CFB boilers) are under development.

The energy effi ciency of CFB units in general scores moderately lower than their PC counterparts for the same steam parameters due to slightly higher parasitic power consumption. With regard to carbon emissions, CFB units are somewhat less competitive because limestone used for in-situ desulphurization emits CO 2 . Capital costs are slightly higher than for PC plants because of the requirements for more auxiliary facilities and anti-erosion refractory.

Cofi ring coal and biomass provides a fl exible method for using biomass, the supply of which may fl uctuate seasonally. Cofi ring coal and biomass reduces net carbon emissions compared to pure coal burning. Cofi ring can also increase the effi ciency of biomass use compared to a small scale power plant fi red purely by biomass. Cofi ring with coal is an effi cient and effective way to use biomass and also to offset carbon emissions from coal power generation, at least until large-scale biomass use for fuel production becomes a reality. As for capital cost, there is one plant in China that has retrofi tted an existing 140 MW PC boiler to utilize up to 20% (heat) biomass. The results also would be indicative for a CFB boiler. The incremental cost corresponding to 20% biomass power is much lower than the specifi c initial capital investment of a new biomass-fi red power plant – and its effi ciency is much higher.


913

dust, and then through flue gas desulphurization to get rid of SO x . The cleaned flue gas returns to the atmosphere via the stack.

Cooling water loop: Low temperature cooling water is sent to the •condenser to condense the exhausted steam at the outlet of the steam turbine. Normally, the lower the temperature of the cooling water, the higher the efficiency of the power plant. Cooling water is supplied either from a water pond within the power plant or from the river or sea. In the first case, water is recycled and a cooling tower is required (as shown in Figure 12.3 ). Evaporation in the cooling tower causes a transfer of cooling water to the atmosphere, comprising the major water use for a power plant.

12.2.2.2 Effi ciency and Steam Conditions

The net efficiency of a power plant is defined as the amount of electric power sent to the grid divided by the total energy input as coal. The effi-ciency depends mainly on the temperature and pressure of the steam as it enters the steam turbine. Coal-steam power plants can be classified as subcritical, supercritical, and ultra-supercritical, depending on the condi-tions of the steam entering the turbine. Steam parameters and typical corresponding efficiency levels are shown in Table 12.3 .

To further improve the efficiency of pulverized coal power plants, development efforts are ongoing on advanced supercritical pulverized coal designs, with steam operating temperatures of 700 ° C. The main hurdles are related to development of high-temperature materials. The efficiency target for such plants is as high as 50% (Quinkertz, 2010 ). Gains in efficiency translate to reduced CO 2 emission/MWh. It is con-ceivable that this technology may become available before carbon capture and storage can be widely applied, because it represents an incremental improvement on a technology with which there is already considerable commercial experience. Thus, this technology may serve to help reduce carbon emissions from coal-fired power generation in the near term.

12.2.2.3 Construction Costs

There were sharp increases in construction costs for new power plants in the middle part of the past decade, particularly in OECD countries. The increases have been especially marked in the United States as evidenced by the much higher rate of increase than GDP of various cost indices rele-vant to the energy and power sectors ( Figure 12.4 ). Table 12.4 provides a view from one power plant equipment manufacturer of the factors influencing cost trends. The main factors contributing to the increasing

Figure 12.4 | Alternative cost indices, each normalized to 100 in year 2000. The Chemical Engineering Plant Cost Index is the most appropriate one to use for many of the energy supply systems discussed in this chapter. Source: updated from Kreutz et al., 2008 .

Table 12.3 | Classifi cation of coal-steam power plants according to steam conditions.

Classification of power plant Temperature (C) Pressure (MPa) Efficiency (%) Typical unit capacity (MW)

Subcritical ~540 16.7 38 300–600

Supercritical ~560 ~25 40–42 600

Ultra-supercritical >560 >25 42–45 600–1000


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costs in OECD countries were (i) substantial increases in raw materials costs, e.g., a quadrupling in the cost of iron ore and a doubling in the price of steel between 2003 and 2008 (IEA, 2008a ), (ii) higher demand for materials generally, (iii) higher crude oil prices, (iv) increases in labor costs due to shortages of engineering, construction, and procurement personnel, and (v) a weakening US dollar during the decade.

Cost escalations for other parts of the world may be different. As an example, Table 12.5 summarizes the actual capital investment for coal and natural gas power in China. The investment levels were quite stable during 2004–2007. The main reason for this is that the major compo-nent technologies are manufactured locally.

In this chapter, unless otherwise indicated, we have expressed costs in US 2007 $. We have used the Chemical Engineering Plant Cost Index (CEPCI) to adjust costs from other year values. As Figure 12.4 shows, using the CEPCI and 2007 as the reference year captures most of the escalation observed in the decade: the index for 2007 is approxi-mately the same as for 2009 (i.e., no relative price increases) and only modestly lower than the preliminary value reported for 2010. 2

12.2.2.4 Carbon Capture from Coal Steam Power Plant

Two approaches can be considered for capture of CO 2 from a steam elec-tric plant. One way is to capture CO 2 from the flue gases of a conventional

plant (referred to as post-combustion capture). A second alternative is to use oxygen rather than air for the combustion (“oxyfuel” combustion). The advantage of the latter over post-combustion is the greater ease of CO 2 separation from the flue gases, which is accomplished by condens-ing out water from the combustion product mix of mainly CO 2 and water vapor. Offsetting this advantage are the significant added costs for an air separation plant and the fundamental power plant redesign required. (See Chapter 13 for additional discussion of this technology.)

Representative mass and energy balances of subcritical and supercritical coal power plants with and without post-combustion carbon capture are shown in Figures 12.5 and 12.6. Their energy, economic and environmen-tal performances are shown in Table 12.6 . 3 , 4 The important messages revealed by comparing power plants without and with CCS are:

The energy efficiency of both subcritical and supercritical power •plants decrease by ~12 percentage points with the addition of car-bon capture and storage. This is mainly due to steam consumption for regeneration of the solvent used to capture the CO 2 and mechan-ical power consumption for CO 2 compression.

Water consumption more than doubles in both cases due to the large •amount of heat required for regenerating the solvent used to capture the CO 2 .

The cost of electricity will nearly double ( Table 12.6 ). •

12.2.3 Gasification-based Power Generation

12.2.3.1 Technology

The first demonstration of gasification-based power generation at a sig-nificant scale dates to the early 1970s in Europe (163 MW plant in L ü nen, Germany (Morehead and Hannemann, 2005 )) and the mid-1980s in the United States (100 MWe Cool Water project (Alpert et al., 1987 )). Since this time there has been considerable development of the technology, several commercial demonstration projects, and a few fully-commercial implementations in applications with low-cost waste feedstocks such

3 In this table, and as much as possible elsewhere in this chapter, we show both lower heating value (LHV) and higher heating value (HHV) for fuels. We have chosen not to use only LHV (the convention in much of Europe) for several reasons: ( i ) LHV can be an ambiguous value in the case of biomass (and we include some analysis of bio-mass/coal systems in this chapter); ( ii ) the US convention for energy prices is HHV; ( iii ) using LHV implies that the latent heat of condensation from combustion of a fuel is not recoverable. In fact, it can, and is, recovered in some circumstances; and ( iv ) use of HHV in this chapter motivates a search for opportunities to capture this latent heat in other applications − and is thus a good index for a carbon-constrained world.

4 These performance and cost estimates (and some subsequent estimates in this chapter) are based on the work of Woods et al. ( 2007 ). At approximately the time the writing of this chapter was completed, an updating of the work of Woods et al. was published (Haslbeck et al., 2010 ). A comparison of estimates in the original study and the revised study reveals only modest differences in plant effi ciencies and installed capital costs. For example, total installed plant costs ($/kW) in the revised study (in US 2007 $) are lower by 1.5–5% for pulverized-coal plants and for natural gas combined cycle plants. Unit costs are 9–16% lower for coal integrated gasifi cation combined cycle (CIGCC) plants.

2 The GEA technical guidelines provide methodological assistance for readers who want to convert these numbers to alternative year prices, e.g. the 2005 numbers used in most other chapters.

Table 12.4 | One power plant vendor’s view of factors infl uencing power plant pricing.

Price trend since 2003

Civil Engineering

Construction Materials (cement, steel, etc.) ↗

Labour costs (local, international) ↗

Power Plant

Main mechanical components (boiler, generator, turbine) ↑ (approx. +270%)

Other mechanical equipment (e.g. piping) ↑ (+150%)

Electrical assembly and wiring: ↑

-cables (+150%)

-transformers (+60%–90%)

Engineering and plant start up ↗

Additional factors

Transportation and logistic costs ↗

Power plant demand ↗

Cost of capital and infl ation →

Note: Vertical arrow (↑) = large increase; slanted arrow (↗) = moderate increase; horizontal arrow (→) =no increase

Source: IEA, 2008a .


915

as petroleum residuals. Gasification-based power generation with fossil fuels, including coal and petroleum residuals, is thus commercial tech-nology, but without widespread operating experience. A distinguishing feature of integrated gasification combined cycle (IGCC) technology is the very low emissions of conventional pollutants that can be achieved, especially SO 2 and particulates. Interest in IGCC has grown recently in part because of the prospectively lower cost of producing low-carbon electricity from coal compared to the cost with pulverized coal (PC) combustion technologies with post-combustion CO 2 capture.

Figure 12.7 is a simplified representation of a coal-IGCC system (CIGCC). Coal, water (or steam), and pure oxygen 5 are fed to a

Rank BituminousSeam Illinois No.6Component Wt% Moisture 11.12 Carbon 63.75 Hydrogen4 .50 Nitrogen 1.25 Chlorine 0.29 Sulfur 2.51 Ash9 .70 Oxygen6 .88Total 100.00

Coal

Infiltration Air

ForcedDraft Fans

Primary Air Fans

Coal Feed

PulverizedCoal

Boiler

SCR

Baghouse

Oxidation AirMakeup Water

Fly ash

Bottom Ash

Induced Draft Fans

FGD

Gypsum

HP IP LP

Feedwater heater system

Condenser

Boiler feedwater

EconamineFG+

COcompr. CO Product

Reboiler Steam

CondensateReturn

Stack

Energy Flow Mass FlowMW kg/s

Vent 17 552CCS 25 817

Air


Vent 1498 55CCS 2212 81

Coal Input


Condenser 739 ---Process 5 ---Condenser 645 ---Process 53 ---

Vent

CCS

Losses Energy Flow Mass FlowMW kg/s

Net Power 592 ---Net plant Efficiency, % HHV (overal 36.8%Net Power 691 ---Net plant Efficiency, % HHV (overal 24.9%

Vent

CCS

Output


VentCCS

PM/Ash


VentCCS

Limestone


Vent - -

0 130 18

CCS (29) 174

CO


Vent 216 645CCS 74 697

Stack Gas


Vent 9 34CCS 13 50

0.6 50.9 8

Gypsum

Vent 392CCS 889

Raw Water UsageVolume Flow, liters/s

Figure 12.5 | Mass and energy balance of a typical subcritical power plant without and with carbon capture (‘Vent’ and ‘CCS,’ respectively). In the case with CCS, the net power output accounts for CO 2 compression to 153 bar, which is assumed to be suffi cient to transport and inject the CO 2 into an underground storage reservoir. Source: based on Woods et al., 2007 .

Table 12.5 | Capital costs (nominal RMB/kW) a for thermal power plants in China.

2004 2005 2006 2007

Type / capacity Cost

(2004 RMB/kW) Cost

(2005 RMB/kW) Cost

(2006 RMB/kW) Cost

(2007 RMB/kW)

Subcritical PC / 2x300 MW 4853 4596 4292 4401

Supercritical PC / 2x600 MW 4074 3919 3608 3643

Ultra supercritical PC / 2x1000 MW 4128 3924 3604 3724

NGCC / 2x300 MW, GE, 9F 3106 3060 3039 3155

NGCC / 2x180 MW, GE, 9E 3137 2946 2912 2998

a For reference, the exchange rate in mid-2008 was US$1 = RMB6.9.

Source: EPPDI and CPECG, 2008 .

5 The oxygen for gasifi cation is produced in a dedicated air separation unit (ASU), with some or all of the air feed to the ASU coming from the compressor of the gas turbine. When 100% of the air used in the ASU originates from the gas turbine, the plant is regarded as fully integrated (and the name integrated gasifi cation combined cycle derives from this feature) and has the highest effi ciency in theory. In practice, however, full integration has proved operationally diffi cult. Most IGCC facilities today consider a maximum of 50% of the ASU air requirement being provided by the gas turbine.


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pressurized gasifier in which partial oxidation reactions occur, along with some water gas shift reaction. The resultant syngas, composed mainly of CO and H 2 , is cooled and cleaned, including removal of essentially all particulate matter, which might otherwise create operating difficulties in downstream processes. Sulfur compounds in the syngas (primarily H 2 S, with some COS (carbonyl sulfide)) are then removed, e.g., using the Selexol ® physical absorption process, to ensure that air emissions limits are met. The syngas is then fed to a gas turbine designed to operate on a CO and H 2 mixture. The turbine generates power, and its high temperature exhaust passes to a heat recovery steam generator (HRSG) to generate superheated steam. The steam drives a steam turbine bottoming cycle to generate additional power.

If CO 2 is to be captured for storage, three additional steps are required (orange shading in Figure 12.7 ). First, the composition of the cleaned syngas is adjusted following gasification via the water gas shift reaction to primarily H 2 and CO 2 . This is followed by capture of both H 2 S and CO 2 in the acid gas removal step, and then by compression of the captured CO 2 to an elevated pressure for pipeline transport to a storage site for underground injection. Typically, CO 2 that would otherwise have been

emitted to the atmosphere can be reduced by 90% using these add-itional steps.

Several different coal gasifier designs are offered by vendors. Two key features that differentiate designs are the type of feeding system (dry coal feed or coal-water slurry feed) and the syngas cooling strategy ( radiant cooling or quench cooling). Dry-feed gasifiers are able to utilize a range of coal types, including lower-rank coals (lignite, sub- bituminous). Slurry-feed gasifiers cannot utilize lower-rank coals because the oxygen requirements for reaching the high temperature needed for effective gasification become prohibitive. Dry-feed gasifiers have higher efficien-cies than slurry-feed gasifiers when both are operating on bituminous coal. On the other hand, slurry-feed gasifiers can operate at considerably higher pressures than dry-feed gasifiers, which can be advantageous in some circumstances. The use of radiant syngas cooling generally pro-vides for higher overall plant efficiency than quench cooling, but also requires greater capital investment. For IGCC-CCS systems, the effi-ciency advantage with radiant cooling is offset to a significant degree by the added benefit with quench cooling of saturating the syngas with moisture, which avoids the need to raise steam for injection to the water gas shift (WGS) reactor.

Rank BituminousSeam Illinois No.6Component Wt% Moisture 11.12 Carbon 63.75 Hydrogen 4.50 Nitrogen 1.25 Chlorine 0.29 Sulfur 2.51 Ash 9.70 Oxygen 6.88Total 100.00

Coal

Infiltration Air

ForcedDraft Fans

Primary Air Fans

Coal Feed

PulverizedCoal

Boiler

SCR

Baghouse

Oxidation Air

Makeup Water

Fly ash

Bottom Ash

Induced Draft Fans

FGD

Gypsum

HP IP LP

Feedwater heater system

Condenser

Boiler feedwater

EconamineFG+

COcompr. CO Product

Reboiler Steam

CondensateReturn

Stack


Vent 16 519CCS 23 740

Air


Vent 1407 52CCS 2007 74

Coal Input


Condenser 643 ---Process 22 ---Condenser 524 ---Process 69 ---

Vent

CCS

Losses Energy Flow Mass FlowMW kg/s

Net Power 589 ---Net plant Efficiency, % HHV (overal 39.1%Net Power 674 ---Net plant Efficiency, % HHV (overal 27.2%

Output

CCS

Vent


Vent 0.CCS 0.9 7

PM/Ash


Vent 2CCS 1 6

Gypsum


Vent 2CCS 0 17

Limestone


Vent

6 5

8 32 4

0 1

- -CCS (26) 158

CO


Vent 195 603CCS 43 624

Stack Gas

Vent 343CCS 767

Raw Water UsageVolume Flow, liters/s

Figure 12.6 | Mass and energy balance of a typical supercritical power plant without and with carbon capture (‘Vent’ and ‘CCS,’ respectively). In the case with CCS, the net power output accounts for CO 2 compression to 153 bar, which is assumed to be suffi cient to transport and inject the CO 2 into an underground storage reservoir. Source: based on Woods et al., 2007 .


917

Table 12.6 | Performance and cost estimates for PC power plants burning bituminous coal.

Subcritical steam cycle Supercritical steam cycle

CO 2 vented or captured/stored → Vent CCS Vent CCS

As-received coal input, t/day 4,768 7,044 4,477 6,386

Coal input, MW HHV 1,496 2,211 1,405 2,004

Coal input, MW LHV 1,427 2,108 1,340 1,911

Gross electricity production, MW 583.3 679.9 580.3 663.4

On-site power consumption, MW 32.9 130.3 30.1 117.5

Net power generation, MW 550.4 549.6 550.2 546

Net generating effi ciency (% HHV) 36.8 24.9 39.2 27.2

Life cycle GHG emissions, a kgCO 2 eq/MWh net 896 187 831 171

CO 2 emissions, kgCO 2 /MWh net 855 126 792 115

SO 2 emissions, gSO 2 /MWh net 357 negligible 335 negligible

NO x emissions, gNO x /MWh net 295 436 277 398

PM emissions, gPM/MWh net 55 81 51 74

Hg emissions, gHg/MWh net 0.005 0.007 0.005 0.007

Installed capital cost (US siting, US 2007 $)

Total plant cost (TPC), million US 2007 $ 880 1,642 894 1,617

Specifi c TCP, US 2007 $/kWnet 1,598 2,987 1,625 2,961

Levelized generating cost, US 2007 $/MWh b

Capital (at 14.38% capital charge rate) 33.1 61.8 33.6 61.3

O&M (at 4% of TPC per yr) 8.6 16.0 8.7 15.9

Coal (at 2.04 US$/GJ, HHV) 19.9 29.5 18.7 26.9

CO 2 transportation and storage 0 7.0 0 6.4

Levelized cost of electricity, US 2007 $/MWh 61.6 114.4 61.1 110.5

a Life cycle GHG emissions include CO 2 emissions at the plant plus emissions (expressed as CO 2 -eq) that occur during coal mining and transportation. b The following assumptions, representing US fi nancial conditions, are adopted for all levelized cost calculations: coal price (US$/GJ HHV ) is 2.04; annual operating and main-

tenance (O&M) costs are 4% of total plant cost; the annual capital charge rate on TPI is 14.38%; TPI is total plant investment (TPC plus interest during construction); the capacity factor for power-only plants is 85%; the capacity factor for plants (described later) that produce liquid fuels or hydrogen (with or without coproduct electricity) is 90%. Also, costs for pipeline transportation and underground injection of compressed (150 bar) CO 2 are estimated based on work by Ogden, 2003 ; Ogden, 2004 , as discussed in Liu et al., 2011a .

Source: Woods et al., 2007 .

Oxygen

Coal CO ₂ 150 bar

Cryogenic air separa�on

unit

Gasifier Syngas cooler/ quench

Par�culateremoval

Syngas cooler

Water gas shi�

Claus plant

H 2 S

Reheat/ humidifica�on

Combined cycle power

island

CO ₂

₂

compressor

CO

Fuel Gas

Electricity

Acid gas removal

Figure 12.7 | Generic representation of coal-IGCC technology. Shaded blocks indicate units added for carbon capture and storage (CCS). When CCS is utilized, the acid gas removal unit is re-designed to capture CO 2 in addition to H 2 S.


918

12.2.3.2 IGCC Energy and Environmental Performance

Figure 12.8 illustrates the rising trend in plant efficiencies for IGCC systems since the first plant was installed in the early 1970s. The fig-ure also illustrates the generally higher efficiencies achievable using dry-feed gasifiers. There is a future potential for raising IGCC efficien-cies through various technological means, e.g., by adapting the latest generation of gas turbines to operate on syngas, by adopting more efficient air separation technologies that are under development today, and others.

A detailed material and energy balance developed by engineers at the US National Energy Technology Laboratory (Woods et al., 2007 ) is shown in Figure 12.9 for a coal-IGCC system using a slurry-feed gasifier and venting CO 2 to the atmosphere. Figure 12.9 also shows a balance for a similar IGCC design, but with CO 2 capture and compres-sion. Table 12.7 summarizes the performance of these two designs and shows estimates also from Woods et al. ( 2007 ) for two alternative IGCC designs using different gasifier technologies. With venting of CO 2 , the electricity generating efficiencies for these three designs range from 38–41% (HHV basis). Capturing 90% of the generated CO 2 and com-pressing it for storage incurs a six to nine percentage point efficiency penalty depending on the design (or a 16–22% reduction in electricity output per unit of coal input). Emissions of conventional pollutants are low, especially SO 2 and PM, regardless of whether CO 2 is vented or captured.

Gasification-based power generation can also be utilized with bio-mass feedstocks. The right two columns in Table 12.7 show perform-ance estimates for biomass-IGCC (BIGCC) systems made for this chapter by a team at the Princeton Environmental Institute (PEI) at Princeton

University. For consistency of comparisons, PEI estimates for two CIGCC systems are also shown. 6 Feedstock collection and delivery logistics for biomass use will generally limit BIGCC plant sizes. The BIGCC systems shown in Table 12.7 are designed for a biomass input capacity of about 3000 t/day dry biomass fed to a pressurized oxygen-blown fluidized-bed gasifier (such as the one originally developed at the Gas Technology Institute (GTI) in the 1980s, the license for which is now owned by Carbona).

With venting of CO 2 , the BIGCC system efficiency exceeds that of a CIGCC system by several percentage points due primarily to three fac-tors: reduced onsite electricity use for supplying oxygen (since bio-mass itself contains some oxygen and the gasification temperature with biomass is much lower than with coal), no requirement for sul-fur removal (since most biomass has negligibly low sulfur content), and less nitrogen injection in the gas turbine for NO x control due to the higher methane content of biomass-derived syngas (which yields lower combustion flame temperatures compared with coal-derived syngas).

A key benefit of utilizing biomass is the negative greenhouse gas emis-sions that can be achieved. Even with CCS, a CIGCC will still release some CO 2 to the atmosphere. When biomass is used, the CO 2 that is stored underground originated in the atmosphere, so net life cycle GHG emissions (including emissions associated with growing the biomass) are negative ( Table 12.7 ).

Figure 12.8 | Development of IGCC net plant effi ciencies for coal-based plants without CCS. Source: Karg, 2009 .

6 The Princeton CIGCC estimates, which are based on designs with slurry-feed gas-ifi cation and syngas quench cooling (rather than radiant cooling), are consistent with the estimates of the National Energy Technology Laboratory, US Department of Energy.


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12.2.3.3 IGCC Economic Performance

The lack of a clear cost advantage for IGCC technology is an important reason that the technology has not yet seen widespread commercial deployment, despite having been first demonstrated commercially in the 1970s. While IGCC systems have clear environmental benefits over combustion systems for coal power generation, the least costly IGCC electricity (under US conditions, Table 12.7 ) is not less costly than elec-tricity from a new supercritical-steam pulverized coal (PC) plant when CO 2 capture/storage is not considered ( Table 12.6 ).

For CIGCC systems with CCS, specific capital costs (US$/kW) increase by 30–40% compared with IGCCs that vent CO 2 ( Table 12.7 ), with corres-pondingly higher levelized costs of electricity generation. But the lev-elized cost of electricity (LCOE) generation for a CIGCC-CCS system is considerably lower than for a PC-CCS system, because supercritical pul-verized coal plants require even higher incremental capital investment for CCS and sacrifice more efficiency points in the process. As shown in Figure 12.10 , the LCOE for CIGCC-CCS reaches the LCOE for a pulverized coal plant with CO 2 venting (PC-V plant) at a much lower GHG emission price (US$55/tCO 2 -eq) compared to that for the PC-CCS plant (US$75/tCO 2 -eq). In the BIGCC-CCS case, although the LCOE at US$0/tCO 2 -eq is much greater than for all the other options shown, its LCOE reaches that for a PC-V plant at a still lower GHG emission price (US$42/tCO 2 -eq) because of the strong downward slope of the LCOE curve that arises from the negative GHG emissions for this option.

12.2.4 Natural Gas Combined Cycle Technology

Natural gas-fired combined cycles are among the cleanest and most efficient fossil fuel based power generating technologies. A natural gas combined cycle (NGCC) consists of a Brayton (gas turbine) cycle, the exhaust heat from which passes through a heat recovery steam gener-ator to raise steam for a Rankine (steam turbine) bottoming cycle. The mass and energy balance shown in Figure 12.11 is for a NGCC with an overall efficiency of 50.8% on a HHV basis. With state of the art gas turbine technologies, NGCCs can reach efficiencies up to about 55% (HHV basis).

Since the hydrogen/carbon ratio of methane is relatively high, the volu-metric CO 2 concentration in the flue gas of a NGCC is low, typically about 5%. The low partial pressure of CO 2 in flue gases requires use of an amine solvent for post-combustion CO 2 capture ( Figure 12.11 ). (See also Chapter 13 .) Regenerating the solvent requires considerable energy, leading to high efficiency penalties for NGCC systems with CCS. In the example case shown in Figure 12.11 , the efficiency penalty is about seven percentage points. More detailed comparison data are shown in Table 12.8 .

To reduce the energy penalty for CO 2 capture, some companies are developing CO 2 recycling processes that re-circulate part of the exhaust gas back to the inlet of the gas turbine compressor, resulting in a higher CO 2 concentration in the flue gases.

GE Gasifier Section ( radiant cooler )

Quench & syngas

scrubber Shift

reactors Gas cooling BFW heating & knockout

Sour water stripper

Mercury removal Selexol unit

Claus plant

Gas turbine

combustor

Elevated pressure

ASU

HRSG

Hydrogenation reactor & gas

cooler

Coal slurry

Slag Gasifier oxidant

Vent gas

Ambient air

Air to ASU

Oxygen

Nitrogen diluent

Turbine cooling air

2 X advanced F class gas

turbines Flue gas

Stack gas

Steam turbine

Syngas Tail gas recycle to

selexol

Clean gas

Sulfur product

Water recycle to coal slurry prep . area

CO compressor

Syngas reheater & expander

Main air compressor

Shift stream CO purification

off - gas

CO product

Rank Bituminous Seam Illinois No.6 Component Wt% Moisture 11.12 Carbon 63.75 Hydrogen 4.50 Nitrogen 1.25 Chlorine 0.29 Sulfur 2.51 Ash 9.70 Oxygen 6.88 Total 100.00

Coal

Vent 253 CCS 289

Raw Water Usage Volume Flow, liters/s Energy Flow Mass Flow

MW kg/s Vent 27 7 CCS 28 7

Slag

Energy Flow Mass Flow MW kg/s

Vent 2 47 CCS 1 29

ASU vent


Vent 34 1077 CCS 36 1121

Air


Vent 1675 62 CCS 1712 63

Coal Input Energy Flow Mass Flow

MW kg/s Net Power 785 --- Net plant Efficiency, % HHV (overall) 38.2% Net Power 758 --- Net plant Efficiency, % HHV (overall) 32.5%

Output

Vent

CCS


Condenser 474 --- Process 208 --- Condenser 419 --- Process 248 ---

Losses

Vent

CCS


Vent 263 1095 CCS 366 1063

Stack Gas


Vent - - CCS (14) 130

CO


Vent 14 2 CCS 14 2

Sulfur

Figure 12.9 | Mass/energy balance for a coal-IGCC plant using slurry-feed gasifi er, radiant syngas cooling without and with CO 2 capture (‘Vent’ and ‘CCS,’ respectively). In the CCS case, the net power output accounts for CO 2 compression to 153 bar, which is assumed to be suffi cient to transport and inject the CO 2 into an underground storage reservoir. Source: based on Woods et al., 2007 .


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Table 12.7 | Estimates for coal or biomass fueled IGCC performance and costs in US 2007 $.

Source of estimate>>> US National Energy Technology Laboratory (NETL) a Princeton Environmental Inst. (PEI) b

Feedstock>>> Bituminous Coal Bituminous Coal Switchgrass biomass

Gasifier technology >>>

GE Energy (slurry)Conoco-Phillips

(slurry)Shell (dry) GEE-Quench GTI fluid bed

CO 2 vented or captured>>>

Vent CCS Vent CCS Vent CCS Vent CCS Vent CCS

Coal input rate

As-received, metric t/day 5,330 5,447 5054 5206 4927 5151 4,477 4,477 0 0

Coal, MW HHV 1673 1709 1586 1634 1546 1616 1,405 1,405 0 0

Biomass input rate

As-received, metric t/day 0 0 0 0 0 0 0 0 3,792 3,792

Biomass, MW HHV 0 0 0 0 0 0 0 0 699 699

Electricity output

Gross production, MW 770 745 743 694 748 694 594 582 348 306

On-site consumption, MW 130 189 119 176 112 176 67 146 31 47

Net exports, MW 640 556 623 518 636 517 528 435 317 259

Effi ciency (HHV) 38.3% 32.5% 39.3% 31.7% 41.1% 32.0% 37.5% 31.0% 45.3% 37.0%

Pollutants, grams per MWh

SO 2 51.4 45.7 49.1 41.7 39.4 50.9

not estimatedNO x 222 223 234 243 220 236

Particulate matter 28.9 34.1 28.1 34.6 26.7 34.7

Carbon dioxide

CO 2 vented, tonne/hr 508 51 489 60 477 46 418 34 224 15

CO 2 stored, tonne/hr 0 469 0 444 0 453 0 385 0 209

LC GHG emis., kgCO 2 eq/MWh

833 138 823 162 787 136 833 126 25 -776

Economics and metrics c

Total plant cost (TPC), 10 6 US 2007 $

1194 1370 1115 1300 1320 1424 1003 1166 636 720

Specifi c TCP, US 2007 $/kWe 1865 2466 1788 2508 2076 2755 1901 2677 2008 2779

Levelized cost of electricity (US 2007 $/MWh) c

Capital (at 14.38% of TPI) 38.6 51 37.2 51.9 43.0 57.0 39.3 55.4 41.6 57.5

O&M (at 4% of TPC per yr) 10 13.2 9.6 13.5 11.2 14.8 10.2 14.4 10.8 14.9

Coal (at 2.04 US$/GJ, HHV) 19.1 22.5 18.6 23.1 17.8 22.9 19.5 23.6 0 0

Biomass(at 5 US$/GJ, HHV) 0 0 0 0 0 0 0 0 39.7 48.6

CO 2 transportation & storage 0 5.6 0 5.9 0 5.9 0.0 6.2 0.0 7.6

Cost of electricity, US 2007 $/MWh

68 92 65 94 72 101 69 100 92 129

a Performance and capital costs from Woods et al., 2007 . Capital costs escalated to January-mid US 2007 $ costs using the ratio of the 2007 average chemical engineering plant cost index to the January 2007 value (1.03). Levelized electricity costs calculated assuming fi nancing parameters described in note (c) below.

b These are previously unpublished estimates that have been made for this chapter using the methodology and assumptions consistent with the work of Liu et al., 2011a . For cases utilizing biomass, the moisture content of the delivered biomass is 15%. No separate biomass drying step is included.

c See note (b) of Table 12.6 for fi nancial parameter assumptions.


921

The minimum GHG emissions price needed to motivate adding CCS to a NGCC plant (US$83/tCO 2 -eq) is even higher than for a PC plant, as a result of the much lower concentration of CO 2 in the flue gas and the smaller amount of CO 2 emitted per kWh of electricity. However, for the assumed fuel prices in Figure 12.10 , the LCOE for NGCC-CCS at this GHG emissions price is lower than for any of the coal options considered.

12.2.5 Health Damage Costs of Power Plants

Air pollution (especially SO x , NO x , and particulate matter) from fossil fuel power generation imposes public health costs that are not reflected in power generating costs discussed to this point in this chapter. The health damage costs vary with the power generating fuel and technology, as well as with income level and demographics of the exposed populations (NRC, 2010 ). There are inherent and large uncertainties in estimating health dam-age costs, but a preponderance of published studies suggests that costs are significant in many cases, especially with coal-fired power generation

HRSG Air

Natural gas

Combustion turbine

Stack gas

Steam turbine

Stack

AMINE

CO 2 compressor

CO 2 product

Boiler steam

Condensate returen

Blower

Cooling water return

Cooling water

Direct contact cooler

Vol.% Methane CH 4 93.9 Ethane C 2 H 6 3.2 Propane C 3 H 8 0.7 n-Butane C 4 H 10 0.4 Carbon dioxide CO 2 1.0 Nitrogen N 2 0.8 Total 100.0

Component Natural gas


Vent 222 895 CCS 68 813

Stack Gas


Vent - - CCS (8) 51

CO 2


Vent 1105 21 CCS 1105 21

Natural gas Input Energy Flow Mass Flow

MW kg/s Net Power 579 --- Net plant Efficiency, % HHV (overall) 50.8% Net Power 529 --- Net plant Efficiency, % HHV (overall) 43.7%

Vent

CCS

Output


Vent 27 874 CCS 27 874

Air


Condenser 323 --- Process 17 --- Condenser 153 --- Process 33 ---

Vent

CCS

Losses

Vent 158 CCS 295

Raw Water Usage Volume Flow, liters/s

Figure 12.11 | Mass and energy balance of NGCC without CO 2 capture (when shaded components are excluded). Including shaded components, the schematic represents NGCC with post-combustion CO 2 capture. For the case with CCS, the net power output accounts for CO 2 compression to 153 bar, which is assumed to be suffi cient to transport and inject the CO 2 into an underground storage reservoir. Source: based on Woods et al., 2007 .

Figure 12.10 | Estimated levelized cost of electricity generation (LCOE) for alterna-tive technologies as a function of GHG emissions price. (See Table 12.6 , Table 12.7 , and Table 12.8 for detailed cost assumptions.) The CIGCC and BIGCC systems shown here correspond to the PEI performance and cost estimates shown in Table 12.7 .) Also shown is the 2007 average price paid to electricity generators in the United States (at zero GHG price) and how this price would change with GHG emissions price if the emissions are assumed to be the US grid-average for 2007 (636 kgCO 2 -eq/MWh).


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located near population centers. We discuss here estimates of costs of damages due to air pollution in the United States, China, and Europe.

The environmental and cost impacts of air-pollution control strategies are explicitly considered in the future-pathways analysis presented in Chapter 17 . Details of the pollutant emissions projections are discussed in Section 17.5.2 , and Section 17.7 concludes that stringent policies for climate mitigation to decarbonize the energy system may bring the co-benefit of reducing air pollution control costs by up to 75% globally, with attendant reductions in health impacts and related damage costs of the type we discuss here. Also Chapter 4 addresses the interaction of energy and health in detail.

12.2.5.1 United States

Since publication of the pioneering Harvard School of Public Health study (Pope III et al., 1995 ), it has been known that the most significant

health hazards from air pollution are associated with small “PM 2.5 ” par-ticles (particulate matter with particle diameters less than 2.5 microns). Inhaled, these small particles become lodged in and build up in the alveoli of the lungs and give rise to significant life-shortening. PM 2.5 particles are emitted directly by power plants and other combustion systems and also formed in the atmosphere from gaseous primary emis-sions of SO 2 and NO x .

One study (Abt Associates Inc., 2000 ) estimated that over 30,000 pre-mature deaths each year were attributable to fine particle pollution from power plants near the turn of the century in the United States. An analysis by the United States Environmental Protection Agency (US EPA, 1997 ) estimated an average life-shortening of 14 years for a person dying prematurely as a result of exposure to fine particle air pollution in the United States.

A recent Harvard School of Public Health study (Levy et al., 2009 ) has systematically assessed the public health damage costs for air pollution from 407 coal power plants in the United States that account for over 90% of US power plant SO 2 and direct PM 2.5 emissions and over 80% of NO x emissions. The most significant health damages are the result of premature deaths arising from PM 2.5 air pollution. The authors of this report estimated median costs of emissions (US$/tonne) based on esti-mated dollar values of the health damages, as well as values at the 5 th and 95 th percentiles for uncertainty. In the left-most column in Table 12.9 , the median estimates of health damages (US$/tonne) from this study 7 are applied to average emission rates for US existing coal power plants in 2007. This table shows that SO 2 emissions account for over 70% of the total health damage costs.

At the median level of health damage cost estimates, the specific cost of health damages (US$87/MWh) is 2.5 times the direct cost of electri-city from a fully-depreciated coal plant (US$35/MWh). 8 At the 5 th and 95 th percentiles of uncertainty (see Table 12.9 , note d) the public health damage costs would amount to 1.3 times and 4.5 times the private cost of generation for written-off plants.

Coal power plant owners would like to keep old written-off units run-ning as long as possible because they are so profitable − the aver-age US selling price for electricity is about twice the generation cost for a written-off plant. However, these plants are profitable only in terms of private costs − not total societal costs. Taking into account

Table 12.8 | NGCC cost, performance, and environmental profi le.

Advanced “F Class” gas turbine NGCC (NETL)

CO 2 vented or captured → V CCS

Natural gas input rate

t/day 1,798 1,798

HHV, MW 1,102 1,102

Electricity output

Gross production, MW 570.2 520.1

On-site consumption, MW 9.8 38.2

Net exports, MW 560.4 481.9

Effi ciency (HHV) 50.8% 43.7%

Pollutants, grams/ MWh net

SO 2 - -

NO x 27.7 32.3

Carbon dioxide

CO 2 vented, t/hr 203.3 20.3

CO 2 stored, t/hr 0.0 183.0

LC GHG emis., kg CO 2 -eq/MWh net 420.8 109.6

Capital costs

Total plant cost (TPC), million US 2007 $ 321 583

Specifi c TCP, US 2007 $/kWe 572 1,209

Levelized cost of electricity (US 2007 $/MWh) a

Installed capital (at 14.38% of TPI) 11.8 25.0

O&M (at 4% of TPC per yr) 3.1 6.5

NG (at US$5.11/GJ HHV ) 36.2 42.1

CO 2 transportation and storage 0.0 3.5

Total cost of electricity, US 2007 $/MWh 51.1 77.1

a See note (b) of Table 12.6 for fi nancial parameter assumptions.

Source: Woods et al., 2007 .

7 Another major study for the United States (NRC, 2010 ) that used a similar method-ology as Levy et al. ( 2009 ) found considerably lower damage costs, highlighting the inherent uncertainties involved in externality costing. Nevertheless, the two stud-ies can be reconciled largely by the fact that the National Research Council study uses a concentration-response function for premature mortality based on Pope et al. ( 2002 ), rather than on the more recent work by Schwartz et al. ( 2008 ).

8 This is based on average conditions for US coal power plants in 2009: HHV effi ciency of 32.6% and an average coal price for power generators of $2.08/GJ (EIA, 2010b) and an operation and maintenance cost of $11.93/MWh for existing coal power plants as estimated in Simbeck and Roekpooritat ( 2009 ).


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health damages from air pollution and considering the low estimate of health damage costs presented in Table 12.9 (5 th percentile of uncer-tainty (see Table 12.9 , note d)) the total cost of generation (private cost for a written-off plant + air pollution damage cost) would be 37% higher than the US average electricity generation price in 2009 (US$58/MWh). This is the case without any cost assigned to green-house gas emissions.

Estimates of health damage costs from air pollution are also indi-cated for alternative new power plants in Table 12.9 , based on emis-sion rate estimates from Tables 12.7 and 12.8. This table shows that damage costs are extremely low for NGCC plants, still significant for new subcritical or supercritical PC-V plants, but quite low for all the plants with CCS. The XTL-CCS plants in the table refer to plants that co-produce electricity and Fischer-Tropsch Liquids (FTL) transporta-tion fuels from X, where X is coal, biomass, or coal+biomass (as will be described in detail in later sections of this chapter). The XTL-CCS plants are characterized by damage costs that are half or less than the damage costs for all the coal stand-alone power plants with CCS. The emission for the PC-CCS plants are low because the SO 2 level in the flue gas has to be reduced to extremely low levels upstream of the

amine scrubber to prevent amine solvent degradation. Similarly, in the XTL-CCS case, protecting downstream process catalysts requires removal of sulfur.

12.2.5.2 China

Studies of health damage costs due to air pollution are more limited for China, and studies specific to pollution from electric power gen-eration are even scarcer. Studies that have estimated public health costs of air pollution in China include those published by the World Bank (World Bank, 1997 ; World Bank and SEPA, 2007 ) and jointly by Harvard and Tsinghua Universities (Ho and Nielsen, 2007 ; Ho and Jorgenson, 2008 ).

The Harvard/Tsinghua study (Ho and Jorgenson, 2008 ) is the only one that has attempted to estimate health damage costs due to power gen-eration in China. It estimated total air pollution damage costs (from all activities) in China using a willingness-to-pay approach (Hammitt and Zhou, 2006 ). The estimated total cost of premature deaths, chronic bronchitis, and asthma attacks was RMB 2002 213 billion, or about

Table 12.9 | Estimated health damage costs (US 2007 $) from air pollution for alternative power plants.

US average coal plant

(2009) a

Subcritical PC b Supercritical PC b CIGCC b NGCC b XTL-OT-

CCS c Vent CCS Vent CCS Vent CCS Vent CCS

Emission rates, kg/MWh

SO 2 2.97 0.357 0.0 0.335 0.0 0.051 0.046 0.0 0.0 0.0

NO x 1.70 0.295 0.436 0.277 0.398 0.222 0.223 0.028 0.032 0.164

PM 2.5 0.196 0.034 0.050 0.032 0.046 0.018 0.021 0.0 0.0 0.016

Health damage costs d , US 2007 $ MWh

SO 2 62.2 7.5 0.0 7.0 0.0 1.1 1.0 0.0 0.0 0.0

NO x 9.0 1.6 2.3 1.5 2.1 1.2 1.2 0.2 0.2 0.9

PM 2.5 15.6 2.7 4.0 2.5 3.6 1.4 1.7 0 0 1.2

Total 87 12 6.3 11 5.7 3.7 3.8 0.2 0.2 2.1

Total relative to average US electricity generation price in 2009

149% 20.1% 10.8% 18.9% 9.8% 6.3% 6.5% 0.3% 0.3% 3.6%

HHV effi ciency of power plant

32.6% 36.8% 24.9% 39.2% 27.2% 38.3% 32.5% 50.8% 43.7% –

a In 2009 total emissions of SO 2 and NO x from coal power plants in the US power sector were 5.19 and 1.81 Mt, respectively (US EIA, 2010a ) when generation from coal in the power sector totaled 1749 million MWh. For PM 2.5 it is assumed that in 2009 the PM 2.5 emission rate is based on the median 1999 estimate of 0.0413 lb per million BTU (17.8 gm/GJ) of coal input for the 407 coal plants investigated in Levy et al. ( 2009 ).

b Emission rates for SO 2 , NO x , and PM from these new plants are from Woods et al. ( 2007 ). For PC plants the emission rates are based on BACT (best available control technolo-gies), exceeding NPPS (new source performance standards) requirements. For CIGCC plants, the emission rates are based on the Electric Power Research Institute’s Coal Fleet User Design Basis Specifi cation. PM 2.5 emissions are assumed to be 0.62 x PM emissions, following Dockery and Pope ( 1994 ).

c For XTL-OT-CCS plants emission rates for NO x and PM 2.5 are assumed to be the same per MWh of gross gas turbine output as for CIGCC-CCS plants, but the SO 2 emission rate is assumed to be zero because protecting synthesis catalysts requires reducing the sulfurous compounds in syngas essentially to zero.

d For 407 US coal power plants (which accounted in 1999 for over 90% of US power plant emissions of SO 2 and PM 2.5 and over 80% of US power plant emissions of NO x ) median estimates of health damage costs were found to be US$20.9, US$5.3, and US$79.3 per kg for SO 2 , NO x , and PM 2.5 , respectively, in 1999 (Levy et al., 2009 ). These valuations were assumed for all the alternative power plants in this table. At the 5 th and 95 th percentiles for uncertainty, the damage costs (in US 2007 $) were estimated to be, respectively, US$11.0 and US$35.3 per kg for SO 2 , US$2.0 and US$9.4 per kg for NO x , and US$45.2 and US$198.4/kg for PM 2.5 . At the 5 th and 95 th percentiles for uncertainty, total health damage costs for US coal-fi red power plants are US$45.0/MWh and US$159.5/MWh, respectively.


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US$30 billion at a nominal exchange rate of 7 RMB/US$. The study also estimated that 28% of the total damage cost, or about RMB60 billion (US$8.6 billion), was attributable to electric power generation. Assuming that most of the health damage was due to coal-fired gen-eration, which accounted for about 81% of power generated in 2002 (1338 TWh) (National Bureau of Statistics China, 2007 ), the estimated health damage cost was about RMB0.044/kWh (US$0.006/kWh) of coal fired generation.

The Harvard/Tsinghua estimate of total health damage cost due to air pollution is on the low end of costs estimated in the joint study by the World Bank and China State Environmental Protection Administration. That study found the average health damage costs in 2003 to be equiva-lent to 1.2–3.3% of GDP (RMB157–520 billion, or US$23–76 billion, assuming 7 RMB/US$). The low estimate was based on a human-capital estimation approach and the high figure was based on a willingness-to-pay approach. Uncertainty ranges in the damage costs were also estimated ( Table 12.10 ). If 28% of total damage costs are attributed to electric power generation (as indicated by the Harvard/Tsinghua study), and coal power generation is assumed to contribute most of these damages, then the range of damage costs per kWh of coal-fired power (1580 TWh in 2003) based on Table 12.10 is RMB0.047–0.14 /kWh (US$0.007–0.02/kWh). 9

Taken together, the World Bank/SEPA and the Harvard/Tsinghua stud-ies suggest that health damage costs from electric power generation in the middle of this decade were equivalent to between 10–40% of the cost of new coal power generation in China today. This is far lower than damage costs estimated for the United States, and is explained in part by the large difference in per capita income between the two

countries, which reduces individuals’ willingness to pay to avoid health damages, as well as lower medical costs in China and fewer health impacts being included in the damage estimates for China as compared to the US estimates (US-China Joint Economic Research Group, 2007 ).

As per capita incomes rise in China, the willingness to pay to avoid health damages will rise proportionately; China’s GDP is expected to more than quadruple between 2005 and 2030 (IEA, 2007 ). At the same time coal power generation is expected to increase substantially, and pollution controls are expected to tighten significantly in this period. Also, the geographical distribution of population in relation to power plants may be significantly different in 2030 from that at present. Studies taking into account trends for these several factors are needed to understand better prospective health damage costs per MWh of coal power generation in the 2030 time frame.

12.2.5.3 Europe

The ExternE Study in Europe was carried out over a period of more than 15 years beginning in the early 1990s. It involved a comprehensive and detailed assessment of air pollution and global warming damage costs from the lifecycle of energy use in Europe, estimated on the basis of the principle of willingness to pay to avoid damages (Rabl and Spadaro, 2000 ; Friedrich, 2005 ). Estimates were published in the late 1990s for 14 countries (CIEMAT, 1999 ) and additional estimates were published in 2004 for three countries in Eastern Europe (Melichar et al., 2004a ). The estimates correspond to the technologies and demographics in these countries in the mid-to-late 1990s. A reassessment of damage costs today would yield different results, but it is difficult to guess whether damage costs would be lower, due to improved pollution controls, or higher, due to higher population densities and higher per capita incomes. (The latter translates into higher levels of willingness to pay to avoid damages.)

The original ExternE estimates indicate that health damage costs from con-ventional power generation in Europe are not inconsequential. Table 12.11

Table 12.10 | Estimated health damage costs in billion RMB 2003 (billion US$) a due to urban outdoor air pollution in China in 2003 (WB and SEPA, 2007) .

Excess deathsChronic

bronchitisDirect hospital

costsIndirect hospital

costsTotal % GDP

Adjusted human capital approach

95 th percentile 178.7 (25.5) 47.7 (6.8) 4.82 (0.69) 0.670 (0.096) 231.8 (33.1) 1.8

Average 110.9 (15.8) 42.5 (6.1) 3.41 (0.49) 0.470 (0.067) 157.3 (22.5) 1.2

5 th percentile 35.8 (5.1) 36.9 (5.3) 1.88 (0.27) 0.264 (0.038) 74.9 (10.7) 0.57

Willingness-to-pay approach

95 th percentile 641.1 (91.6) 136.7 (19.5) 4.82 (0.69) 0.670 (0.096) 783.3 (111.9) 4.9

Average 394.0 (56.3) 122.1 (17.4 3.41 (0.49) 0.470 (0.067) 519.9 (74.3) 3.3

5 th percentile 135.6 (19.4) 106.2 (15.2) 1.88 (0.27) 0.264 (0.038) 243.9 (34.8) 1.6

a Estimated costs in 2003 Yuan RMB have been converted to US$ using a nominal exchange rate of 7 RMB/US$.

9 Another study, involving some of the same authors as the Harvard/Tsinghua study, estimated health damage costs from SO 2 emissions in the power sector to be RMB6555/t (US-China Joint Economic Research Group, 2007 ). The average SO 2 emissions rate from coal-fi red power plants in China in 2005 was 5.4 g/kWh (based on total SO 2 emission from power sector of 11.12 million tonnes (Gao et al., 2009 ) and 2,047 TWh of thermal power generation (National Bureau of Statistics China, 2007 ). This gives a much higher damage cost estimate of RMB0.36/kWh (US$0.051/kWh using a nominal exchange rate of 7 RMB/US$).


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shows these estimates by country for coal and for natural gas-fired power generation. Damages with coal are considerably higher than with natural gas. Also, there is a wide range in estimates for coal-fired generation dam-ages from one country to another. Costs in Finland and Sweden are under US$5/MWh, most likely reflecting the low density of populated areas, the high level of pollution control technologies, and the modest amount of coal-fired power generation in these countries. The majority of countries in Western Europe have damage costs in the range of US$40–80/MWh – comparable to the cost of electricity production for a new coal-fired power plant. At the extreme high end is Hungary at US$114/MWh.

12.3 Technological Changes at Refineries and Opportunities for CCS

12.3.1 Context

12.3.1.1 Demand for Liquid Fuels

Liquid fuels are the world’s single largest source of energy and are expected by many to remain so for decades to come. The United States

Energy Information Administration (US EIA) ( 2010b ) forecasts an increase in world liquid fuel consumption from 86 million bbl/day in 2007 (192 EJ/yr) to 111 million bbl/day in 2035 (248 EJ/yr) ( Figure 12.12 ). The US EIA projects this increase to occur primarily in non-OECD Asia (a 93% increase for that region), followed by Central and South America, and the Middle East. Liquid fuel share of world energy use drops from 35% in 2007 to 30% in 2035, still remaining the single largest glo-bal source of energy. The vast majority of these liquids (96% in 2007 and 80–91% projected for 2035) are from conventional petroleum, with the rest coming from unconventional sources, including heavy oil and tar-sand bitumen (processed in refineries and tar sand upgraders), bio-fuels, coal-to-liquids and gas-to-liquids plants ( Figure 12.13 ). Biofuels, such as renewable diesel, may be coprocessed in oil refineries but are unlikely to amount to more than 1% of total refinery throughput by 2035. Transportation accounted for nearly half of all liquid consumption in 2007, with industry accounting for about a third. The transportation fraction is projected to reach 60% by 2035, with industry falling to 29% ( Figure 12.14 ).

These projections are consistent with trends over the past decade. From 1998 to 2008, petroleum consumption grew by 15%, with Central and

Table 12.11 | Estimated health damage costs of power generation in 17 European countries, as of mid/late 1990s.

Health damage costs (US 2007 $ per MWh)

COAL NATURAL GAS

Power Plant Emissions Other

fuel cycle Total

Power Plant Emissions Other

fuel cycle Total

Country a Mortality Morbidity Mortality Morbidity

Austria 2 1 0 3

Belgium 25 4 0 29

Czech Rep. b 9 4 5 17

Finland 3 1 1 5

France 65 13 0 79 15 3 0 18

Germany 17 2 2 21 4 1 2 7

Greece 3 1 0 4

Holland 11 2 0 13 3 1 0 4

Hungary b 76 37 1 114 6 3 0 9

Ireland 47 9 0 57

Italy 9 2 0 11

Norway 0 0 0 0

Poland b 30 19 6 56

Portugal 26 5 11 42 0 0 0 1

Spain 35 6 1 42 5 1 0 6

Sweden 1 0 2 3

UK 32 6 0 38 4 1 0 5

a Except for Czech Republic, Hungary, and Poland, original estimates given by CIEMAT, 1999 in 1995 ECU/MWh have been converted to US 2007 $/MWh by assuming 1.25 US$/ECU and using the ratio of 2007:1995 US GDP defl ators (1.3).

b Original estimates given by Melichar et al., 2004b in 2002 Euro/MWh have been converted to US 2007 $/MWh by assuming 1.25 US$/Euro and using the ratio of 2007:2002 US GDP defl ators (1.15).


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South America, China, India, and the Middle East accounting for 72% of the increase (BP, 2009 ). The US EIA projection is also largely consistent with projections in The Outlook for Energy: A View to 2030 (ExxonMobil, 2009 ). ExxonMobil has forecast world liquid fuel demand of 108 million bbl/day by 2030 (241 EJ/yr), with transportation fuel demand of 62 mil-lion bbl/day (138 EJ/yr). They expect 94% of the latter demand to be met from oil, 5% from biofuels, and 1% from natural gas. In this Outlook , US demand for transportation fuels peaks around 2015 and declines by 10% to 13 million bbl/day by 2030 (29 EJ/yr), the European Union demand stays flat at about 9 million bbl/day (20 EJ/yr), and China’s demand triples to 8 million bbl/day (18 EJ/yr).

The IEA ( 2009a ) forecasts global oil demand of 105 million bbl/day in 2030 (234 EJ/yr) with 97% of the increase from transportation fuels and all growth in the non-OECD countries. Their 450 Scenario (an aggressive timetable of actions to limit atmospheric greenhouse gas concentration to 450 ppm CO 2 -eq) projects oil demand lower by 12 million bbl/day (27 EJ/yr), but still higher than current demand.

Forecasts of biofuel use are in the range of 3–6 million bbl/day by 2030 (6.7–13 EJ/yr). ExxonMobil expects about 3 million bbl/day (6.7 EJ/yr) with 30% from US corn ethanol, 30% from Brazil sugar cane and the remaining from biodiesel worldwide. The US EIA ( 2009b ) forecasts 5.9 million bbl/day (13 EJ/yr), assuming that cellulosic technology will be significant from 2012.

12.3.1.2 Crude Oil Supply

World oil reserves have increased steadily over the past several decades, despite periodic predictions to the contrary. They have increased from

998 billion barrels (bbl) in 1988 (6088 EJ) to 1069 billion bbl in 1998 (6521 EJ) to 1258 billion bbl (7674 EJ) at the end of 2008 (BP, 2009 ). Current proven reserves are sufficient for the next 40 years and it is widely assumed that additional reserves are yet to be discovered. (See Chapter 7 for additional discussion of oil reserves.) There is a significant mismatch, however, between the location of reserves and the centers of demand for liquid fuels. This mismatch is likely to become more pro-nounced. For example, regions where 75% of fuel demand is located hold only 9.5% of the current reserves ( Table 12.12 ). The extensive need to import crude oil that major fuel consuming countries face will con-tinue, with its concomitant supply security concerns. It should be noted, however, that, since the first short oil embargo and the Iranian revolu-tion in the mid- and late seventies, and despite several wars and con-flicts in oil-producing regions, there has been no world supply disruption that would justify uneconomic or environmentally unsound measures and investment for the sake of “security.” Indeed, the world’s fastest-growing oil importer, China, has successfully embarked on a course of securing supplies all over the world through alliances and outright acquisition of reserves.

Crude oil is primarily categorized and priced by its gravity and sulfur content with heavier, more sour crudes being the cheapest and most dif-ficult to process into usable, lighter fuels. About 20% of world reserves are classified as “sweet,” i.e., light, low sulfur crudes, 65% are “light or medium sour,” and 15% “heavy sour.” This mix will change slowly over the next couple of decades, probably with more sour and heavy sour crudes in production. Any new refining capacity being built now will readily accommodate anticipated crude mix changes.

Estimates for reserves of heavy and extra heavy oil, bitumen from oil sands, and shale oil vary depending on technology and economic

Figure 12.12 | World liquids consumption by region. Source: based on US EIA, 2010a .


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feasibility assumptions but are generally considered to be approxi-mately 3735 EJ and resources in place to be approximately 56,000 EJ ( Table 7.8 ), with only a minor fraction produced to date.

12.3.1.3 Oil Refi ning Capacity

Global refining capacity ( Table 12.13 ) increased by 11% in the last dec-ade with 69% of the increase occurring in China, India and the Middle East and 15% in the United States. These numbers do not include the new 580,000 BD refinery added to the Reliance complex at Jamnagar (India) that started up in 2009 and makes Jamnagar one of the lar-gest and most modern refinery sites in the world. Nor do the numbers include the 240,000 BD Fujian refinery expansion that also started in 2009 in China. Future capacity additions will generally follow the liquid

Figure 12.14 | Projections of world liquids consumption by sector. Source: based on US EIA, 2010a .

Table 12.12 | Oil reserves and consumption by region in 2008.

Reserves 10 9 bbl (EJ)

Consumption 10 3 bbl/d (EJ/yr)

% of Reserves % of Consumption

World 1,258 (7,674) 84,455 (188) 100 100

United States 30.5 (186) 19,419 (43) 2.4 23.0

European Union 6.3 (38.4) 14,765 (33) 0.5 17.5

China 15.5 (94.6) 7,999 (18) 1.2 9.5

Middle East 754 (4,599) 6,423 (14) 59.9 7.6

Asia Pacifi c (incl.China) 42 (256) 25,339 (57) 3.3 30.0

North America (incl.US) 70.9 (432) 23,753 (53) 5.6 28.1

N. Am., Asia Pac., & EU 119.2 (727) 63,857 (142) 9.5 75.6

Source: BP, 2009 .

Figure 12.13 | Projections of world liquids supply in 2035 for three alternative oil price projections. Source: based on US EIA, 2010a .


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fuels demand with most new capacity expected in non-OECD Asia. In the United States and the European Union, some capacity will be shut down for economic reasons (e.g., in 2010 Valero announced the per-manent shutdown of its Delaware refinery, or 7% of its capacity, and BP announced plans to sell its Texas City, Texas, and Carson, California, refineries) while some revamps and expansions will occur in the United States for processing heavy Canadian crude. China is expected to add around 3 million bbl/day of capacity by 2015 while shutting some of the smaller, less efficient refineries that have a combined capacity of between 1 million bbl/day and 1.5 million bbl/day.

12.3.2 Refining Technology and Economics

Refineries are complex processing plants that can generally handle a wide range of crude oil feedstocks and produce hundreds of products of varying specifications. No two refineries are alike. Each one has been designed for a particular market and presumed crude slate and then modified over time as product specifications, environmental regula-tions, and crude supply economics evolve. The complexity of a particular refinery results from the trade-off between the costs of investment and operating vs the capability to process heavier, less expensive crudes and produce lighter, higher-value transportation fuels or petrochemicals.

The major conversion processes in refining have not changed funda-mentally for about six decades, though there have been steady, sig-nificant improvements and occasional breakthroughs in product yields, product quality, energy efficiency, and environmental performance. A brief description of refining technology as well as a detailed analysis of life cycle GHG emissions of petroleum-based fuels has been given by the National Energy Technology Laboratory, US Department of Energy (NETL, 2008 ).

Briefly, crude oil is heated in fired furnaces and separated into different boiling point fractions in atmospheric and vacuum distillation columns. The simplest refining configuration today is a hydroskimming/topping refinery processing a light sweet crude. It includes only a reformer and a distillate hydrotreater in addition to distillation. The reformer increases

the octane of gasoline-range boiling material (naphtha) by dehydro-genating naphthenes into aromatics, isomerizing linear paraffins into branched ones, and converting paraffins into aromatics over a fixed-bed catalyst at moderate pressure. Hydrogen is produced as a by-product. The hydrotreater removes sulfur in a high pressure hydrogen atmos-phere by converting it to hydrogen sulfide, also over a fixed bed catalyst. Such a refinery would produce LPG, gasoline, kerosene/jet fuel, diesel/heating oil, and a large amount (30–35%) of low-value heavy fuels.

The next step would be to add a fluid catalytic cracker (FCC) to con-vert some of these heavy fuels, products from the vacuum distillation column, into diesel, gasoline and lighter gases. The FCC is a complex, atmospheric pressure process where oil vapor is contacted with a fluid-ized circulating catalyst. Coke is deposited and then burned off continu-ously from the catalyst in a regeneration step. The FCC is a major source of refinery carbon dioxide and other emissions. In modern refineries, a great deal of equipment is required to reduce sulfur/nitrogen oxides and catalyst particulate emissions from FCC units. An FCC feed hydrotreater, operating at higher pressure than the distillate hydrotreater, would desulfurize the FCC feed and improve the FCC light product yields by saturating aromatic rings. Such a medium conversion refinery would process higher-sulfur crudes and create higher value products than the hydroskimming refinery.

The next step would be to add a coker, a thermal cracking process that can handle the heaviest residue from vacuum distillation and convert it to diesel, gasoline, lighter gases and solid petroleum coke. Such a high conversion refinery could handle the heaviest crudes in its feed and create the maximum value-added between feed and products. In the early 1980s some complex catalytic units were built to hydrotreat heavy residues but the simpler coking process has been the economic choice worldwide since then.

Another major conversion process is hydrocracking, which handles feed similar to the FCC but cracks it in a very high pressure hydrogen atmosphere over a fixed catalyst bed. A refinery can have either of the two catalytic cracking processes or both. Hydrocracking capacity world-wide is about one third that of FCC. Hydrocracking is preferable when a

Table 12.13 | Refi ning capacity 1988–2008, 10 3 bbl/day.

1998 2008 Capacity increase % increase% of world capacity

increase

World 79,699 88,627 8,928 11 100

United States 16,261 17,621 1,360 8.4 15

European Union 15,262 15,788 526 3.4 6

Central and South America 6,114 6,588 474 7.8 5

Middle East 6,202 7,592 1,390 22 16

China 4,592 7,732 3,140 68 35

India 1,356 2,992 1,636 121 18

Source: BP, 2009 .


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higher diesel/gasoline ratio is needed and is particularly suited for mak-ing very-low-sulfur products. Other refinery processes include (i) naph-tha hydrotreating, necessary to treat the reformer feed or for gasoline fractions to meet current low-sulfur specifications, (ii) alkylation that converts FCC gases into high-octane gasoline material, (iii) isomeriza-tion, a reforming process that increases the octane of light naphtha, (iv) visbreaking, another thermal process for heavy residues, and (v) a multitude of treating processes to remove impurities and contaminants from various intermediate and product streams.

As refinery complexity and feedstock flexibility increases, more severe hydrotreating for distillates and FCC feed may require more hydrogen than is produced by the reformer; a hydrocracker will definitely require another source of hydrogen. A refinery then needs a hydrogen plant or needs to import hydrogen from an external facility. Most refineries use natural gas and refinery off-gas to produce hydrogen through steam reforming. There are several options and technological opportunities in this area. In 1999, BOC Gases (now a part of The Linde Group) and BP Amoco developed a partial oxidation scheme using the Texaco gasification process to supply hydrogen to a new refinery hydrocracker in Bulwer Island, Australia, and to recover pure carbon dioxide (Ramprasad et al., 1999 ). Depending on the investment cost and the availability or cost of natural gas, refineries can also use gasification of residues or even of petroleum coke. The Shell Group’s Pernis refinery in the Netherlands, one of its largest facilities at 400,000 bbl/day, chose a 1650 t/day heavy residue gasification route to produce hydrogen for a new hydrocracker (Shell, 2009 ).

12.3.2.1 Heavy Oils Technology

The production of heavy oils and bitumen from tar sands generally requires use of steam in one of several techniques, e.g. cyclic steam stimulation, steam assisted gravity drainage, horizontal cyclic steam, or some combination of these (Anonymous, 2008 ). If heavy oil is to be transported to a distant refining center, lighter oil must be used as dilu-ent to allow flow in a pipeline. Alternatively, such oil can be partially processed where it is produced and a “syncrude” product then shipped to conventional refineries. The processing of very heavy oil or tar sands occurs through application of essentially conventional refining technol-ogy. Coking is the major conversion process, followed by severe hydrot-reating of the ensuing products before further processing. As crude oil prices rose in the 2004–2007 period, a great deal of investment was initiated to upgrade Canadian tar sands and to process Canadian heavy oil in northern US refineries.

12.3.2.2 Refi ning Economics

Refining is a capital-intensive and competitive industry that has not been particularly profitable in the long term, except for short periods and in specific “niche” markets. The most recent example is the “Golden Age” of refining in the United States, lasting less than four years, which

was caused by a steep global demand increase and unexpected shut-down of refining capacity. Refining margins are determined by market forces and are affected primarily by factors such as the balance between product demand and available refinery capacity, the differential price between heavy and light crudes, and the global balance of fuel oil. (High differentials and low fuel oil prices tend to cause refineries with simpler “topping” configurations to cut production as their variable margins reach break-even and to favor refineries with cracking capacity that can convert the heavier oils.)

As with other commodities, periodic overbuilding of capacity has caused margins to be cyclical and weather or operational variations in avail-able capacity have caused volatility. New capacity costs have histor-ically been around US$10,000/bbl/day of capacity but have risen to US$20,000–30,000 in recent years. Generally, margins have not justi-fied new capacity construction in OECD countries. Government policies or incentives, niche supply or market conditions, or particular synergies with other petrochemical or power projects have supported new cap-acity additions, primarily in Asia. With the Golden Age in the past, non-mandatory investments in refining will be difficult to justify in OECD countries in the future.

12.3.3 Greenhouse Gas Emissions

12.3.3.1 Extent of Refi nery Emissions in the Life Cycle of Petroleum-based Fuels

Emissions of carbon dioxide from stationary fossil fuel sources account for 60% of total global fossil fuel emissions. Of the major stationary sources, refineries account for 6%, cement manufacture for 7%, and power generation for 78% (CO 2 Capture Project, 2009). A detailed ana-lysis of life cycle GHG emissions of petroleum-based fuels has been conducted by NETL ( 2008 ; 2009 ). The scope of this work is extensive and includes analysis of the impact of different crude sources on the GHG emissions of transportation fuels sold in the United States. A sum-mary of some of their results is given in Figure 12.15 . Not surprisingly, a key conclusion is that the extent of GHG emissions that is attributed to refinery processing itself is small (6–10%), compared to the ultimate use of the fuels (80–83%). NETL ( 2008 ) conclude that the best way to reduce transportation life cycle GHG emissions is by lower overall use of fuels through more efficient modes of transportation and vehicle efficiency. They estimate, as an example, that seven miles per gallon improvement in light vehicle efficiency would be equivalent to elimin-ating all oil production, transportation, and processing “well-to-tank” emissions. They consider refineries already efficient and cite ongoing continuous improvement programs in the US industry. Although their study is centered on US transportation fuels, this conclusion is quite general. New capacity in Asia is being built to very high standards of efficiency and environmental performance and, as smaller, less efficient refineries are phased out for economic as well as environmental rea-sons, global refinery emissions will decrease on a continuing basis.


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Emissions from the production and transportation of heavy oils are higher by 9.5–14 kgCO 2 /GJ LHV diesel (NETL, 2009 ), than those from more con-ventional crudes, which vary by comparable amounts from each other. An analysis of the GHG emissions associated with the production and trans-portation of different crudes and heavy oils must be conducted in terms of global impact. There is little overall benefit, for example, if the use of par-ticular crude or heavy oil is limited in the United States through a carbon tax or other regulatory measures only to route this crude to an alternative refining center elsewhere in the world. Opportunities for reducing flaring during production, which are higher for some crudes, no doubt will be pur-sued. The upgrading of heavy oil lends itself to carbon capture and seques-tration. Refineries constantly optimize their crude mix on a global basis based on the demand of their market, their configuration, and the cost of crudes relative to their value for a specific refinery. If a globally consist-ent and well-designed cap-and-trade system emerges, the cost associated with specific feedstocks, including conventional crudes, heavy crudes, or tar sands, should lead to the optimal use of all global resources.

12.3.3.2 Opportunities for Carbon Capture from Refi nery Emissions

Carbon dioxide capture at a refinery has been studied by the CO 2 Capture Project, a partnership of seven major energy companies working closely with government organizations, academic bodies, and global research

institutes (CO 2 Capture Project, 2009). The major sources of emissions considered are boilers and fired heaters, fluid catalytic cracker units, and hydrogen production operations. The FCC unit has its own intrin-sic combustion emissions due to coke burning during catalyst regener-ation. Emissions from other major processes, such as crude distillation, hydrotreating, and hydrocracking, are generated by fired heaters used in the process. Fired heaters can be treated as a group and are amen-able to common analysis, optimization, consolidation, and carbon cap-ture approaches. Three CO 2 capture approaches are being considered:

post-combustion: absorption of flue gas CO • 2 from major sources into MEA (monoethanolamine) solution;

oxy-firing: use of oxygen instead of air in combustion to produce a high •concentration of CO 2 in the flue gases thus facilitating capture; and

pre-combustion: gasification to produce a hydrogen-rich fuel and •separate CO 2 prior to combustion.

Two recent studies associated with CO 2 Capture Project have considered opportunities for carbon capture in refineries. Shell (van Straelen et al., 2009 ) has evaluated the feasibility of post-combustion capture at a world-scale refinery. They identified scale (1–2 MtCO 2 /yr) and CO 2 con-centration (above about 8%) to be major factors in the cost-effectiveness

Totals 91.1 90.1 87.8

Wel

l-to-

Tank

Wel

l-to-

Whe

els/

Wak

e

Conven�onalGasoline

Conven�onalDiesel

Kerosene-Type Jet Fuel

Crude Oil Extrac�on 6.9 6.3 6.4

Crude Oil Transport 1.3 1.2 1.2

Refinery Opera�ons 9.3 9.0 5.7

Finished Fuels Transport 1.0 0.9 0.9

Combus�on of Fuel 72.6 72.7 73.6

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

GHG emissions(kgCO2-eq/GJ LHV)

Figure 12.15 | Baseline life cycle emissions of CO 2 -eq for fuels derived from petroleum and sold or distributed in the United States in 2005. Source: based on NETL, 2009 .


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of refinery carbon capture. They concluded that the best opportunities lie in capturing the emissions from hydrogen production (5–20% of refinery emissions) and large flue gas stacks (another 30% of emissions), finding smaller sources unlikely to be practical. They estimated that such carbon capture would be economical at carbon trading “3–4 times higher than the current.” Shell is also studying opportunities for oxy-firing burners and operating the FCC regeneration on oxygen, so as to facilitate CO 2 capture from flue gases. Petrobras and Lummus (de Mello et al., 2009 ) have studied post-combustion and oxy-firing the FCC and concluded that oxy-firing is feasible and more cost-effective although it would entail higher investment. They did not show absolute cost estimates for using such technology.

The FCC is a major source of refinery emissions. This process has been dominant globally and especially in China for a number of reasons. It was the choice of Reliance for the new refinery in Jamnagar, Gujarat, India. For new capacity, understanding the impact of high carbon costs on the choice of catalytic cracking technology would be worthwhile, especially if demand for diesel continues to increase, as it has in Europe over the last decade.

12.3.4 Conclusions

Current refining technology is likely to continue as the major source of liquid fuels for the next few decades. The global refining industry will grow with some capacity shifting from the OECD, especially the United States, to non-OECD Asian countries, primarily China. Significant technological or regulatory breakthroughs would be needed to change this course, given the scale, technological maturity, and economic fun-damentals of this industry. Nevertheless, material opportunities for continuous improvement to decrease refinery GHG emissions and for carbon capture exist and should be developed further.

12.4 Transportation Fuels from Non-petroleum Feedstocks

Fossil fuels other than petroleum can be converted to transportation fuels. Technologies are available and commercially operated today for converting natural gas, coal, or biomass into liquids that closely resem-ble diesel and gasoline derived from crude oil. These processes involve converting the gas, coal, or biomass first into a synthesis gas (primar-ily CO and H 2 ) that is then reacted over specialized catalysts to form liquid hydrocarbons. The most widely used synthesis process for making transportation fuels today is Fischer-Tropsch (F-T) synthesis. The crude Fischer-Tropsch liquid product (FTL) can be refined into middle distil-late fuels (65–85% of the final liquid volume produced), naphtha or gasoline (15–25% of the final product), and heavy waxes or lubricat-ing oils (0–30% of the final product) (Fleisch et al., 2002 ). Oxygenated fuels, such as methanol, higher alcohols (C3 to C8, propanol to octa-nol), or dimethyl ether (DME), can also be produced from synthesis gas

using different catalysts, and methanol can be further processed cata-lytically into synthetic gasoline and synthetic liquefied petroleum gas (LPG). There are other technologies, not yet commercialized, that pur-sue conversion through other intermediates than synthesis gas such as acetylene (Biello, 2009 ) or methanesulfonic acid (MSA) (Richards, 2005 ). Technology is also available for direct liquefaction of coal to produce a mix of products, including synthetic gasoline, diesel, LPG, and jet fuel, as well as a variety of chemicals.

12.4.1 Gas to Liquids

It is estimated that nearly 40% (or 71 trillion cubic meters) of the world’s current natural gas reserves are “remote” or “stranded,” defined as too far from the market place for economic delivery via pipelines. Natural gas resources in Australia, Trinidad and Tobago, and Qatar are good examples. In these instances, gas monetization is sought via liquefying the gas for shipping. The siting of facilities to re-gasify liquefied natural gas is now very challenging in many countries so, increasingly, gas mon-etization is being pursued via conversion to liquid fuels and chemicals. The high oil prices of recent years are providing a significant impetus for these so-called gas-to-liquids (GTL) efforts. Another driver for the advancement of GTL is the reduction or elimination of the flaring of associated gas. Rather than flaring gas associated with crude oil pro-duction, it could be converted via GTL technology into a synthetic crude oil and blended with the produced crude oil for shipping to refineries. The estimated 425 million cubic meters of gas flared daily if converted via GTL technology could produce some 1.5 million bbl/day (3.3 EJ/yr) of additional liquid hydrocarbon products.

Billions of dollars have been invested in GTL technology development over the last several decades by major oil companies and several tech-nology companies. The investment has been primarily in technology for Fischer-Tropsch conversion. (The term GTL in popular usage usually refers to Fischer-Tropsch systems.) A lower level of investment has gone into technologies for producing other liquids, including methanol, higher alco-hols, DME, and synthetic gasoline (via methanol). At current rates of com-mercial deployment, GTL systems could be displacing as much as 1 million bbl/day (2.2 EJ/yr) of petroleum-derived transportation fuels by 2020.

12.4.1.1 Fischer-Tropsch Technology

Transportation fuels are produced by Fischer-Tropsch processing, with chemical feedstocks as byproducts. F-T systems consist of three major integrated sub-systems: (i) syngas production, (ii) syngas conversion to a syncrude, and (iii) syncrude upgrading to finished products.

First, syngas (consisting predominantly of CO and H 2 ) is produced from methane (CH 4 ) by reforming using one of a variety of proven technologies. For smaller plants, steam methane reforming (SMR) is the technology of choice where natural gas is reacted with steam at


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high temperatures and pressures in an externally-heated multi-tubular reactor over a nickel-based catalyst. At plant sizes over about 10,000 bbl/day, autothermal reforming (ATR) or partial oxidation reforming (POX) have become the norm. (The larger size justifies the costs of a dedicated onsite air separation unit for oxygen production.) In these systems, part of the natural gas is combusted with oxygen and the hot combustion products (CO 2 and H 2 O) react with additional natural gas over a nickel-based catalyst to form syngas. Most of the heat require-ments of the endothermic reforming reaction are met by the heat from the combustion process.

Following reforming, syngas is converted over a catalyst into predomin-antly long chain paraffinic hydrocarbons with water as a side product. The reaction is quite exothermic and great care must be taken to remove the heat from the reaction vessels. Cobalt-based catalysts have become the norm because of their much higher activity and selectivity for pro-ducing the desired paraffins compared with traditional iron-based cata-lysts. The former are optimized to produce a heavy wax intermediate and reduce the formation of lighter material (C1 to C5). The CO 2 yield from the F-T reactor is less than 1%. The wax is hydrotreated with add-itional hydrogen in the “upgrading” section to make primarily diesel and naphtha as well as other high value materials such as lube oils, jet fuel, and detergents. The iron-based catalysts produce a broader product portfolio including branched hydrocarbons (gasoline), olefins, and oxy-genates along with the paraffins. They still find applications in coal-to-liquids because of the water gas shift activity of these catalysts, which produces additional hydrogen from CO through reaction with water. Coal-to-liquids are discussed further in Section 12.6 .

Upgrading of F-T syncrude to finished products, the third and final step in a GTL system, is a well-proven conventional refining step. Paraffinic hydro-carbon chains are hydrocracked into shorter chains, predominantly in the diesel range (C 8 to C 13 hydrocarbons). A small desirable degree of isomeri-sation can be achieved to provide proper diesel blending properties.

The basic catalytic reaction for syngas conversion was discovered in the 1920s by Franz Fischer and Hans Tropsch, two German scientists. It was sparingly used after its discovery, but there has been a resurgence of interest over the last 30 years supported by billions of dollars of research and development investments. A number of technologies that use pro-prietary catalysts have been developed by Sasol, Shell, ExxonMobil and other companies:

Sasol, a South African company, has almost 50 years of experience with •F-T technology, mostly in connection with coal conversion. Current production at their Sasolburg and Secunda facilities in South Africa is about 135,000 bbl/day (from coal). Cumulative production of F-T fuels using Sasol technology exceeds one billion barrels. The Sasol process has undergone significant advancements over the years from the ori-ginal fixed bed technology (Arge process) to a circulating bed process (Advanced Synthol Process). The Petroleum Oil and Gas Corporation of South Africa (PetroSA), the state-owned GTL producer, started up its

Mossgas plant in 1993 based on Sasol technology and now produces 22,500 bbl/day of finished products. The latest Sasol technology devel-opment is its Slurry Phase process. The process was commercialized in the Oryx GTL facility in Ras Laffan, Qatar, in 2006, which produces about 34,000 bbl/day and cost nearly US$1 billion to build. The process involves bubbling hot syngas through a slurry consisting of catalyst par-ticles suspended in liquid hydrocarbon products. The capacity of a sin-gle Sasol slurry reactor is 17,500 bbl/day. In partnership with Chevron and the Nigerian National Petroleum Corporation, Sasol is providing technology, engineering services and engineering support for the con-struction of a carbon-copy of the Oryx facility on a site adjacent to the Escravos River in Nigeria. The Escravos GTL plant will convert about 8.5 million cubic meters per day of currently-flared gas into 22,300 bbl/day of diesel, 10,800 bbl/day of naphtha and 1000 bbl/day of LPG. The pro-ject was hit by global construction cost escalations starting in 2007 and may end up costing more than five times the same-sized Oryx plant, some US$5.9 billion.

Shell is the other leader in commercial gas-to-liquids experience as a •result of its GTL plant in Bintulu, Malaysia (the Shell Middle Distillate Synthesis plant). The Shell technology is a tubular fixed bed reactor containing a proprietary cobalt-based catalyst. The Bintulu plant was designed to convert 2.8 million m 3 /day of gas into 12,500 bbl/day of GTL products. It started operation in May 1993. In 1997, an explo-sion in the air separation unit damaged the plant. The plant was rebuilt and production restarted in mid-2000 and has been operating since that time at full capacity. The Bintulu plant was the inspiration for Shell’s Pearl gas-to-liquids project in Ras Laffan, Qatar. Pearl is designed to produce 140,000 bbl/day in four trains of 35,000 bbl/day each. The trains are planned to come online between 2011 and 2014. The overall project cost announced in 2001 of US$5 billion has ballooned to allegedly US$20 billion (nominal estimate, circa 2008), mainly due to escalating construction costs. However, the oil price has risen fourfold as well, making all products more valuable and compensating for the higher capital costs.

ExxonMobil’s Advanced Gas Conversion for the 21st Century (AGC-21) •is a Fischer-Tropsch hydrocarbon synthesis process that converts syn-gas to heavy hydrocarbons over a cobalt-based catalyst suspended in a slurry. The AGC-21 hydrocarbon synthesis technology is protected by about 1200 patents and has not yet been operated commercially. In the last decade, ExxonMobil explored several commercialization options. It advanced a 160,000 bbl/day project in Qatar, but aban-doned the project (and perhaps the technology) in 2006.

BP has been involved with GTL technology since the 1980s. It oper- •ated a GTL test facility in Nikiski, Alaska, from 2002–2009 and con-tinues to pursue commercial applications. The test facility converted about three million cubic feet of natural gas into an estimated 300 barrels of synthetic crude a day. The BP technology uses a cobalt-based catalyst in a tubular fixed bed reactor. BP is licensing the technology and is pursuing projects around the globe.


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Conoco was an aggressive player in GTL starting in 1998, pursu- •ing a catalytic partial oxidation process for syngas production and a slurry phase reactor with cobalt-based catalyst for F-T conversion. A 400 bbl/day pilot plant in Ponca City, Oklahoma, was approved in 2001, and a large commercial project in Qatar was being pur-sued. However, the technology was abandoned shortly after Conoco merged with Phillips in 2002.

Rentech is focused on the development of an iron-based cata- •lyst in a slurry-phase process to be able to utilize syngas derived from not only natural gas but also solid or liquid hydrocarbon feedstocks. The Rentech F-T process was verified in a 235 bbl/day facility in Pueblo, Colorado, in 1993. Rentech is licensing their technology and pursing numerous projects with different feedstocks.

Syntroleum’s GTL process has been under development since the •1980s. It involves the use of a cobalt-based catalyst in a slurry to convert syngas produced from a proprietary air-fed autothermal reformer. A 70 bbl/day demonstration facility was successfully oper-ated, but no commercial project has advanced.

World GTL in partnership with Petrotrin, the Petroleum Company of •Trinidad and Tobago, is building a small GTL plant using a refurbished and re-engineered methanol plant. They have developed their own cobalt based, multi-tubular F-T technology. There have been signifi-cant cost overruns and the project went into receivership in 2010. Nevertheless, the 2,250 bbl/day plant is expected to come on line in 2012, and World GTL is targeting small gas fields and associated gas with its low-cost modular technology.

There are a number of related advanced technology developments •underway. Petrobras is piloting a micro-reactor based GTL system developed by Velocys and CompactGTL (CompactGTL, 2010 ). Micro-reactors are low-cost modular systems where the reactions and the heat exchange are conducted in small channels of about 1mm diam-eter. These systems have a much smaller footprint than conventional systems and could be deployed on platforms or floating vessels to convert off-shore associated gas. Another major development under-way for more than 15 years is the use of ionic membranes to sep-arate oxygen from air and to react the oxygen with natural gas to syngas. A smaller footprint and cost reduction of 25% or more over conventional reformers have been touted by the lead developer, Air Products (Air Products, 2008 ).

Energy and Environmental Performance of F-T Systems The energy efficiency of a large modern commercial GTL plant today (see Figure 12.16 ) is about 60–65% on a LHV basis (53–58% HHV basis). Its carbon efficiency (fraction of carbon input as natural gas that appears in the liquid products) will reach 75–80%. For comparison, the methanol process is more efficient than GTL with today’s advanced technologies

already having energy and carbon efficiencies of about 70% and 85%, respectively.

Two processes basically determine the overall efficiency of a GTL plant: (1) the inherent water production in the conversion of methane to higher hydrocarbons (typically one barrel of water will be produced for every barrel of hydrocarbon liquid) and (2) process fuel losses, which refers to the combustion of some of the feed methane (or fuel gas derived therefrom) to provide the heat needed for reforming. From a theoretical perspective, the overall methane-to-liquids reaction can be represented as:

12 4 2 12 26 2( ) (( )) 12 26 (( )) ( )H O+x CO211 225 5 25 5 25 5 25 5 111111 ) (x225 5 25 5 25 55 5 1111 2 (1)

The maximum efficiency will be for the case where x is zero (no net CO 2produced). This theoretical maximum is 78% (LHV). The remaining 22% of the input energy went into making water. At this maximum thermal efficiency, the methane carbon conversion into liquid products would be 100%. For a carbon efficiency of 75% (approximately the level with current technology), x is about three. Technology advances are projected to raise energy and carbon efficiencies to as high as 73% and 90%, respectively, within the next decade (Fleisch et al., 2003 ). This would make the carbon efficiency of the GTL process comparable to that of petroleum refining.

For a large, modern GTL facility that vents CO 2 , the life cycle GHG emis-sions associated with the F-T liquid products amounts to some 101 kgCO 2 -eq/GJ LHV (where GJ stands for gigajoule) or about 10% above GHG emissions associated with an equivalent amount of crude-oil

ASU

RefiningSteampowergen.

LiquidPhase FTSynthesis

Syngascooling

GasPreheat

ATR

Fuel gas

Natural gas9.2x106 m3/day3974 MW ��3580 MW �

(196 tC/d)

F-T Liquids34,000 bpd

2316 MW ��2168 MW �

(157 tC/d)

O 2steam

syngas

air

steam

Electricity(for onsite)

Flue gas

Fuelgas

Figure 12.16 | Overall energy and carbon balance for a modern two-train GTL facil-ity. Source: based on Simbeck and Wilhelm, 2007 .


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derived products. 10 , 11 The prospects for reducing these emissions are limited, since only a relatively small amount of CO 2 is available for cap-ture. If available CO 2 were to be captured at a GTL facility today, life cycle GHG emissions would be about 10% below emissions from an equivalent amount of crude-oil derived products. The expectation is that further advances in GTL technology will reduce the amount of CO 2 avail-able for capture, which makes this figure a lower bound on potential GHG emissions of GTL fuels.

Prospective F-T Economics The gap is widening between the value of natural gas and that of liquid transportation fuels such as diesel and gasoline, influenced by oil prices consistently above US$60/bbl and increasing bullishness regarding future natural gas supplies (see Section 12.7.2.2 ). In the largest market, the United States, gasoline and diesel sold for two to four times Henry Hub natural gas prices on an energy equivalent basis in recent times (Henry Hub is the pricing point for natural gas futures contracts traded on the New York Mercantile Exchange). During most of the 1980s and 1990s, gas hovered around US$2/GJ while diesel and gasoline averaged US$4–6/GJ. More recently, the gap has widened because of plentiful gas supplies and the capping of gas prices by coal in the competition for power generation. In 2009 , we have seen gas prices below US$3/GJ while low sulphur diesel was at US$14/GJ and above. These are strong economic drivers for GTL especially with commercially proven technolo-gies. It can be shown that at oil prices of US$60/bbl, a delivered gas price of about US$8/GJ is needed to achieve a similar net present value for GTL and LNG (liquefied natural gas) projects. At higher oil prices and/or lower gas prices, GTL is economically advantaged over LNG while at lower oil prices and/or higher gas prices LNG is the economic choice.

The economics for an integrated upstream gas field and GTL plant will typically be more attractive than those for a stand-alone GTL plant. Shell’s 140,000 bbl/day Pearl project is an example of an integrated project. It includes gas production platforms, gas processing plants and the GTL facilities. The economic returns from the condensates and LPG in the natural gas are high, putting less demand on the return from the GTL project.

Capital costs of GTL Fischer-Tropsch projects dropped from about US 2005 $80,000 per bbl/day (US 1991 $60,000) of installed capacity in 1991 for Mossgas to just below US 2005 $29,000 per bbl/day (US 2006 $30,000) installed capacity for Oryx in 2006. These costs made GTL economic with oil at US$20/bbl. Capital costs have more than doubled in the last four years, however, due to sky rocketing oil prices and the corresponding

increases in project costs in the oil and gas industry. Many GTL projects have been delayed for a “cooling down” period. However, the first train of the Shell Pearl project started up in mid-2011, to be followed by the other three trains through 2014. This project may prove the techno-economic attractiveness of large scale GTL once and for all and set the stage for widespread global applications with ongoing improvements. Meanwhile, research and development is continuing and will also con-tribute to reducing capital costs as it has in the past.

Thus, GTL has the potential to become a prominent part of the inter-national energy business. Continued high oil prices and the widening gap between gas prices and oil prices will favor GTL projects. Most importantly, the concerns of technology risks will wane with commer-cial plants operating safely and reliably around the world. The problem of technology access will disappear: an increasing number of licensing opportunities and patents are expiring.

12.4.1.2 Methanol to Gasoline

Production of methanol from natural gas is a well-established tech-nology (Cheng and Kung, 1994 ; Olah et al., 2009 ). Methanol consump-tion globally exceeds 40 Mt/yr primarily in chemical processing. Use of methanol as a vehicle fuel attracts considerable interest in some prov-inces of China today (Dolan, 2008 ), as it did in the 1970s and 1980s in the United States, where interest has since faded largely as a result of health and environmental concerns from the use of methanol-derived MTBE (methyl tert-butyl ether) as an additive to gasoline. There is renewed interest in higher alcohols for both gasoline and diesel blend-ing (IGP, 2010 ). These alcohols overcome some disadvantages of metha-nol and ethanol and have been shown to increase engine efficiencies and lower tailpipe emissions (Yacoub et al., 1997 ). Furthermore, there is now growing interest in China, the United States and elsewhere in the production of synthetic gasoline from synthesis gas via a methanol intermediate. This so-called methanol-to-gasoline process is the subject of this section.

The first step is methanol production by reforming of natural gas into synthesis gas (CO and H 2 ), which is then converted over a catalyst to methanol. The two most common reforming technologies, SMR and ATR, have been described in Section 12.4.1.1 . A syngas H 2 /CO ratio of about two leaving the reformer will optimize methanol synthesis yields, but reforming typically yields a syngas with H 2 /CO higher than two. One option for reducing the H 2 /CO ratio is to feed recycled CO 2 to the reformer. Katofsky (Katofsky, 1993 ) showed that this has the benefit of increasing methanol yield and overall process efficiency by several percentage points.

Two companies currently offer technology for synthesis of gasoline from methanol. A key distinction between the technologies is that the tech-nology offered by Haldor Topsoe utilizes an initial single-step conver-sion of syngas into DME/methanol, followed by conversion to gasoline

10 This estimate includes 9.10 kgCO 2 -eq/GJ LHV associated with extraction, preprocess-ing, and transportation of the feedstock natural gas (based on the GREET model (Argonne National Laboratory, 2008 )).

11 If natural gas that would otherwise have been fl ared (a relatively small potential resource for GTL) were the feedstock, then the net life cycle GHG emissions associ-ated with these GTL fuels would be considerably less than for equivalent petroleum-derived fuels, since the GTL fuels would be displacing the petroleum-derived fuels (FWI, 2004 ) while eliminating the emissions from the fl ared gas.


935

in a separate reactor (Nielsen, 2009 ). The ExxonMobil process involves methanol production from syngas followed by partial conversion of methanol to DME in a separate reactor, followed by conversion of the DME/methanol mixture into gasoline in a third reactor (Tabak et al., 2009 ). In either case, most of the DME/methanol mixture that flows to the gasoline synthesis reactor is converted in a single pass over the catalyst. Some propane/butane (LPG) and a small amount of methane are coproducts.

Because the H/C ratio of methane is higher than that of the final gas-oline product, no significant CO 2 by-product stream is available for cap-ture and storage, giving natural gas-to-MTG systems a carbon footprint not substantially different from petroleum-derived gasoline.

12.4.2 Direct Coal Liquefaction

Direct coal liquefaction refers to a process in which pulverized coal reacts with a hydrogen-donor solvent over a catalyst, causing hydroc-racking of the coal into liquids. Direct liquefaction is distinct from indir-ect liquefaction. As discussed in Section 12.4.3 , indirect liquefaction utilizes coal gasification followed by a separate catalytic step to convert the gasified product into liquid fuels. (Fischer-Tropsch fuels are perhaps the best known of the different fuels that can be produced via indirect liquefaction.)

Direct coal liquefaction will produce not only gasoline, diesel, LPG, and jet fuel, but also a variety of chemicals such as benzene, toluene, xylene, and other raw olefins to further produce ethylene and propylene. The reaction can be summarized as follows:

nC n H C Hn Hn H( )nn 2 2 2C Hn nH→ + (2)

The first generation of direct coal liquefaction technology was devel-oped during World War II. Germany was the first country to realize the industrialization of direct coal liquefaction. Twelve direct coal liquefaction plants were built and the total capacity exceeded 4 Mt/yr. However, the first generation technology was limited by its harsh reaction condition (Pressure: around 70 MPa) and costly catalysts. After World War II, all the plants were shut down due to technical defects and economic disadvantage driven by the development of cheap oil. The 1970s oil crisis brought attention back to direct coal liquefaction. Many countries developed a wide range of modern coal liquefaction technologies (Pressure: 10~30 MPa and less expensive catalysts): American H-Coal and Hydrocarbon Technology, Inc. (HTI), the German Integrated Gross Oil Refining (IGOR) technology, the Japanese NEDOL technology, and others. These technologies com-pleted 350~600 t/day pilot tests but did not achieve large scale industrialization. Table 12.14 lists known technologies developed to at least the 50 t/day coal input scale. The main differences between these processes lie in catalysts, reactors, hydrogen donor solvents, and system design.

The most active country today in direct liquefaction is China, which became a net oil importing country in 1993. Since then, the fraction of oil imported has been increasing, and it reached about 50% by the end of 2008. Concern about energy security gives impetus for making oil from coal in China. Direct coal liquefaction became a major candidate because it is believed to be more energy efficient and less water con-suming than many alternatives.

In 2001, China’s Shenhua Group, the largest coal company in the world, started development of a demonstration project to produce one Mt/yr of liquids from coal by direct liquefaction. In early 2009, the facility conducted the first test run which lasted about 300 hours and then shut down as planned. This project is ongoing and is expected to provide improved understanding about potential energy and economic perform-ances of this technology (see Box 12.2 ).

12.4.2.1 Process Description

Direct coal liquefaction includes a catalytic liquefaction step in the presence of hydrogen followed by solid-liquid separation and upgrading. Pulverized coal is blended with a solvent and the catalyst, together making a coal slurry. In the liquefaction unit, weak-bond breaking is achieved, leading to free radical hydrogenation. Then, the inorganic minerals and un-reacted coal are removed by a series of solid-liquid separation processes such as vacuum distillation, filtration, extraction, and sedimentation. Finally, a catalytic hydrogenation process is required to increase the hydrogen-to-carbon ratio in the liquid product and remove impure elements.

Generally speaking, apart from anthracite, all other types of coal can be liquefied to some extent. In rough terms, the difficulty of liquefaction increases with the age of the coal: peat < young lignite < lignite < high-volatile bituminous coal < low-volatile bituminous coal. In addition, excessive ash content also has a negative impact on coal liquefaction.

Table 12.14 | World testing of coal liquefaction technologies.

Single stage processes Two stage processes

• Kohleoel (Ruhrkohle, Germany) • NEDOL (NEDO, Japan) • H-Coal (HRI, USA) • Exxon Donor Solvent (EDS) (Exxon,

USA) • SRC-I and II (Gulf Oil, USA) • Imhausen high-pressure (Germany) • Conoco zinc chloride (Conoco, USA)

• Catalytic Two-Stage Liquefaction (CTSL) (USDOE and HRI, now HTI, USA)

• Liquid Solvent Extraction (LSE) (British Coal Corp., UK)

• Brown Coal Liquefaction (BCL) (NEDO, Japan) • Consol Synthetic Fuel (CSF) (Consolidation

Coal Co, USA) • Lummus ITSL (Lummus Crest, USA) • Chevron Coal Liquefaction (CCLP) (Chevron,

USA) • Kerr-McGee ITSL (Kerr-McGee, USA) • Mitsubishi Solvolysis (Mitsubishi Heavy

Industries, Japan) • Pyrosol (Saarbergwerke, Germany) • Amoco CC-TSL (Amoco, USA) • Supercritical Gas Extraction (SGE) (British

Coal Corp., UK)

Source: DTI, 1999 .


936

The liquefied oil from direct coal liquefaction, including naphtha, diesel, and liquefied heavy oil, retains some characteristics of raw coal, such as a high content of aromatic hydrocarbons and hetero-atoms (e.g., Oxygen, Nitrogen). A process of hydrogenation is carried out to upgrade the quality of the liquefied oil, which causes the refining costs to be much higher than for conventional petroleum refining.

12.4.2.2 Resource Consumption and Economic Performance

Compared with indirect coal liquefaction and other coal conversion technologies, the efficiency of direct coal liquefaction is higher, up to 60%. Shenhua estimates that the coal consumption of a direct coal liquefaction project is about 0.061 tonne of coal equivalent (tce) per

Box 12.2 | Shenhua Direct Coal Liquefaction Demonstration Project

China’s Shenhua Group’s direct coal liquefaction demonstration project in Ordos, Inner Mongolia Autonomous Region, China, is designed to produce 1 Mt/yr of oil. The Chinese government approved the project in 2001, construction started in August 2004, and the fi rst testing run succeeded in early 2009 .

Shenhua developed its own synthetic catalyst to lower costs. Hydrogen donor solvent cycle is used to mitigate the slurry properties. A slurry bed compulsory intra-circulation reactor is used to improve the capacity of reaction. A mix of advanced and mature unit technologies reduces project risks.

The process fl ow of Shenhua direct coal liquefaction project is shown in Figure 12.17 . At present, 1.08 Mt of liquefi ed oil can be produced with the input of 4.10 Mt of coal, of which 1.32 Mt is used for hydrogen production and 0.53 Mt for industrial boiler fi ring. Of the liquefi ed oil, 70% is diesel and 20% is naphtha. The naphtha products, with a high content of aromatics, are very good reforming materials. The water consumption in this project is about 7 to 8 tonnes of water per tonne of product.

Figure 12.17 | Shenhua direct coal liquefaction demonstration project process fl ow.


937

GJ of liquid product, compared with 0.075 tce/GJ for indirect coal liquefaction.

Water consumption is always a big concern for coal conversion. Compared to other conversion technologies, direct coal liquefaction appears to be relatively lower in specific water consumption at about 8 t water per metric tonne of product (t/t), compared with about 11–12 t/t for indirect coal liquefaction. Water is mainly consumed in the gasifi-cation unit for providing hydrogen for hydrocracking and the hydrogen-ation upgrading processes.

The investment of a direct coal liquefaction plant is still uncertain. The first-of-a-kind plant may cost US$100,000 to US$150,000 per bbl/day output capacity. This number can be decreased with further technology development and improvements in engineering.

12.4.2.3 Carbon Dioxide Emissions

In a coal liquefaction plant producing one Mt/yr of liquids, the carbon dioxide emissions will amount to more than 3.6 Mt/yr, excluding emis-sions from combustion of the liquid products. The plant CO 2 emissions are predominantly (about 80% of emissions) from the hydrogen pro-duction unit. The CO 2 leaves this unit in high concentration (87–99%), which can facilitate low-cost capture of CO 2 for underground storage. (Other CO 2 -containing emission streams, e.g., flue gas from the flare system, have relatively low concentrations of CO 2 , making capture for storage more difficult.) About one-third of carbon input as coal is available for capture as a relatively pure stream from the H 2 produc-tion plant. In this respect, direct coal liquefaction has some similarity to gasification-based coal-to-fuels and coal-to-chemicals processes, since a pure stream of CO 2 is available (just as there is in gasification-based processes). For additional discussion of direct versus indirect liquefac-tion, see Williams and Larson ( 2003 ) and Lepinski et al. ( 2009 ).

12.4.3 Gasification-based Liquid Fuels from Coal (and/or Biomass)

There is growing interest in making synthetic fuels from coal − known as coal-to-liquid (CTL) fuels − in light of coal’s relatively low prices and the abundance of coal in China, the United States, and other countries that are not politically volatile. Much of this attention has been focused on so-called indirect liquefaction to produce Fischer-Tropsch liquids (Bechtel Corporation et al., 2003 ; van Bibber et al., 2007 ; Bartis et al., 2008 ; AEFP, 2009 ). Synthetic gasoline (made via a methanol intermedi-ate, see Section 12.4.1.2 ) is also beginning to attract interest (AEFP, 2009 ).

Coal can do much to improve energy security if it is used to make liquid fuels. Moreover, these synfuels would be cleaner than the crude oil products they would displace (having essentially zero sulfur and other

contaminants and low aromatics content). Also, if produced using mod-ern entrained flow gasifiers, the air pollutant emissions from the pro-duction facility would be extremely low. When synthetic fuels are made from coal without capture and storage of by-product CO 2 , however, net fuel-cycle GHG emissions are about double those from petroleum fuels they would displace (AEFP, 2009 ). And even with carbon capture and storage (CCS), the net GHG emission rate would be only about the same as the crude oil products displaced.

One approach to reducing GHG emissions below petroleum-fuel levels is to exploit negative GHG emissions opportunities to offset the emissions. One important opportunity is synthetic fuels production from biomass with CCS (Larson et al., 2006 ). An intrinsic feature of synthetic fuels pro-duction from coal or biomass is the production of a by-product stream of pure CO 2 , accounting for about one half of the carbon in the feedstock. If this CO 2 can be captured and stored via CCS while producing synthetic fuels from sustainably grown biomass, the biofuels produced would be characterized by strong negative GHG emissions, because of the geo-logical storage of photosynthetic CO 2 . However, sustainably-recovered biomass is expensive, and the size of the biomass-to-liquid (BTL) facil-ities will be limited by the quantities of biomass that can be gathered in a single location − which implies high specific capital costs for BTL.

The shortcomings of the BTL with CCS option could be overcome to an extent by coprocessing biomass with coal in the same facility. The econ-omies of scale inherent in coal conversion could thereby be exploited and the average feedstock cost would be lower than for a pure BTL plant. And if CCS were carried out at the facility, the negative CO 2 emis-sions associated with the biomass could offset the unavoidable positive emissions with coal ( Figure 12.18 ), leading to liquid fuels with low, zero, or negative fuel-cycle emissions depending on the relative amounts of coal and biomass input (AEFP, 2009 ; Larson et al., 2010 ; Liu et al., 2011a ). Interest in the CBTL-CCS concept is growing in the United States (Tarka et al., 2009 ).

The equipment for gasification-based production of liquid fuels from coal and biomass are commercial or nearly-commercial in all cases. Coal gasifiers are commercially available and deployable today, with more than 420 gasifiers already in commercial use in some 140 facil-ities worldwide (AEFP, 2009 ). The technology for cogasifying biomass and coal is close to being ready for commercial deployment; the com-mercial Buggenum IGCC facility in the Netherlands has been cogasify-ing coal and some biomass in a coal gasifier since 2006 (van Haperen and de Kler, 2007 ). Stand-alone biomass gasification technology is an estimated five to eight years from being ready for commercial-scale deployment (AEFP, 2009 ). Technologies for converting syngas into Fischer-Tropsch diesel and gasoline are in commercial use today. Those for making synthetic gasoline via methanol can be considered com-mercially deployable (AEFP, 2009 ), with technology offered by vendors such as Haldor-Topsoe (Nielsen, 2009 ) and ExxonMobil (Tabak et al., 2009 ), and projects in development (Doyle, 2008 ; ExxonMobil, 2009 ). See Section 12.4.1.2 .


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12.4.3.1 Process Descriptions

Figure 12.19 illustrates generically gasification-based production of liquid fuels from coal or biomass. The feedstock is gasified in oxygen and steam, with subsequent gas conditioning that includes cleaning of the raw synthesis gas (syngas) and in some cases adjusting the com-position of the syngas using a water gas shift reaction to achieve the requisite H 2 :CO ratio for downstream catalyst-assisted synthesis into liquids. Prior to synthesis, CO 2 and sulfur compounds are removed in

the acid gas removal step to increase the effectiveness and reduce the required size of downstream equipment, as well as avoid sulfur poison-ing of catalysts. The CO 2 may be vented (-V) or captured and stored underground (-CCS). The liquid fuel synthesis island is designed with recycle (RC) of unconverted syngas to maximize liquids production. A purge stream from the recycle loop, together with light gases generated in the refining area, provide fuel for power generation, which primarily goes to meet onsite needs. (Alternatively, as discussed in Section 12.6 , if none – or only some – of the unconverted syngas is recycled, the

Figure 12.18 | Carbon fl ows for conversion of coal and biomass to liquid fuels and electricity. When biomass is approximately 30% of the feedstock input (on a higher heating value basis), the net fuel cycle GHG emissions associated with the produced liquid fuels and electricity would be less than 10% of the emissions for the displaced fossil fuels. Source: Larson et al., 2010 .

Powergenera�on

Liquid fuelsynthesis

Acid gasremoval

Gascondi�oning

Oxygenproduc�on

Feed prepara�onand gasifica�on

air

feed-stock

CO2 H2S, COS OnsiteElectricity

FinishedFuels

Refining

Figure 12.19 | Production of liquid fuels from coal and/or biomass feedstocks.


939

unconverted syngas can be used to increase electricity generation and provide an exportable electricity co-product.)

More detailed process depictions of coal conversion into F-T fuels are shown in Figure 12.20 (blue and yellow shading). Figure 12.21 shows coal conversion to synthetic gasoline. In these particular plant designs, a slurry of bituminous coal and water is fed into a pressu-rized gasifier along with oxygen from a dedicated onsite cryogenic air separation unit. The syngas leaving the gasifier is wet-scrubbed before some of it enters a water gas shift reactor. The fraction of the syngas sent to the WGS reactor is adjusted to ensure an appro-priate H 2 :CO ratio for the later synthesis reactor. Following the WGS reactor, the syngas is cooled in preparation for acid gas removal and, in the case of F-T production, expanded to near the pressure required

for later synthesis. CO 2 and H 2 S are then removed by the acid gas removal system. Several acid gas removal technologies are commer-cially available (see Chapter 13 ). A physical absorption process using chilled methanol (e.g., Rectisol ® ) is indicated in Figures 12.20 and 12.21. The captured H 2 S is processed via a Claus/SCOT system into elemental sulfur. The captured CO 2 can be either vented to the atmos-phere or compressed to a supercritical state for pipeline delivery and underground injection for storage. Following acid gas removal, the syngas is delivered to the synthesis reactor.

In the case of F-T synthesis ( Figure 12.20 ) most of the syngas passes to the synthesis reactor, where it reacts over a catalyst to produce a mixture of olefinic and paraffinic hydrocarbons. When an iron-based synthesis catalyst is used, the syngas H 2 :CO ratio entering the reactor

Gasi fi ca � on & Quench

Grind in g & Sl urry Prep

water

coal

Syngas Scrubber

Acid Ga s Rem oval

F- T Re fi ni ng

F- T Synthesis

CO 2

Fl as h Re frig era� on

Pl an t

slag

Fl as h

me thanol

CO 2

syngas

Wa ter Ga s Shif t

150 bar CO2 to pipeline

Re ge nerato r

H 2 S + CO 2

To Claus/SC OT

HC Recov er y

Recyc le Co mp r.

fi ni she d gasol ine & dies el bl endstocks

unco nverted syngas + C 1 -C 4 FT gase s

raw FT prod uct

Re fi nery H 2 Pr od

syncru de lig ht ends

purge ga s Powe r Islan d

net exp or t electr ic ity

ga s coo li ng

expa nder

ATR oxyg en steam

fl ue ga s

oxyg en

Oxyg en Pl an t

air

Compression needed only if CCS is u�lized.

FB Gasifier & Cyclone

Chopping & Lock ho pper

biom ass Ta r

Crac king

steam

CO 2 dry ash

ga s coo li ng

Filter

oxyg en

Oxyg en Pl an t

air

Figure 12.20 | Alternative process confi gurations for maximizing production of FTL from coal (CTL-RC-CCS, blue-shaded components) or from biomass (BTL-RC-CCS, green-shaded components) with capture and storage of carbon. Yellow-shaded components are common to both CTL and BTL systems.

s

t

tp

Figure 12.21 | Plant confi gurations for maximizing gasoline output with only coal as input feedstock.


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is about one, and the raw liquid product is a mix of hydrocarbons with a wide range of carbon numbers. With a cobalt-based catalyst, the ratio is about two, and the liquid product is largely heavy hydro-carbons (waxes). After synthesis, unconverted syngas and light gases generated during synthesis are recycled back to the synthesis reactor to increase F-T liquids production. (In some situations, separation for sale of the light components that constitute LPG may be economic.) The recycled gases undergo ATR to convert light hydrocarbons, result-ing in a stream returning to the synthesis reactor that consists primar-ily of CO, H 2 , and CO 2 . A small portion of the recycle gases are drawn off as a purge stream to avoid the buildup of inert gases in the recycle loop. The purge gases are mixed with light hydrocarbons produced in the F-T refining area, and the mixture of gases is burned in the boiler of a steam turbine power system. Electricity production is primarily to meet onsite needs.

The final step in FTL production is refining of the raw liquid product (mostly a crude diesel and naphtha). Hydrogen addition is typically required in this step. In the design shown in Figure 12.20 , some syn-gas is diverted upstream of synthesis for use in producing the requisite hydrogen. A minimum refining step is required to stabilize the liquid products if they are to be shipped to a conventional refinery for further refining. This minimum step includes hydrogenation of the naphtha and diesel range hydrocarbons and hydrocracking of the heavier hydrocar-bons (waxes). Alternatively, further refining to finished diesel and gas-oline blendstocks can be done onsite. Reforming of the naphtha fraction is required in this case to produce an acceptable gasoline blendstock (Liu et al., 2011a ; Guo et al., 2011 ). The naphtha could be sold instead as a chemical feedstock, thereby avoiding added cost and energy expendi-tures for catalytic reforming, but chemical markets for naphtha are rela-tively small (compared to gasoline markets), so this would be a limited option if FTL production were to become widespread.

In the particular process shown in Figure 12.21 for making synthetic gasoline via methanol (MTG) from syngas, the first step following acid gas removal is methanol synthesis, for which the requisite syngas H 2 :CO ratio is about two and optimal pressure is 50–100 bar (considerably higher than for F-T synthesis). Most of the unconverted syngas is recycled to increase methanol production, with a small purge stream extracted to avoid building up inert gases. (No reformer is required in the recycle loop as in the FTL design, since there is no significant hydrocarbon con-tent in this stream.) The crude liquid methanol is vaporized and sent to a DME reactor, where it is catalytically converted to an equilibrium mixture of methanol, dimethyl ether and water. The mixture flows to the MTG reactor, where most of the gas is converted in a single pass over a cata-lyst into gasoline-range hydrocarbons. Some propane/butane (LPG) and a small amount of methane are coproducts. The liquid products are sent for fractionation and finishing (primarily durene treatment), resulting in finished gasoline and LPG products. The purge gas from the methanol synthesis area and light gases evolved in the MTG area fuel the power island, where a steam cycle generates all the electricity needed to run the facility plus a modest amount of export electricity.

Process designs for making FTL or MTG from biomass feedstocks would be similar to those described above for coal conversion. Figure 12.20 shows a configuration for FTL from biomass (BTL) (green plus yellow shading). There are important differences from the coal design (also shown in Figure 12.20 ): (i) a pressurized fluidized-bed gasifier, which avoids the energy-intensive grinding of biomass that is required with an entrained flow gasifier and enables ash to be removed as a dry mater-ial that might be returned to the field for its inorganic nutrient con-tent; (ii) a tar cracking step following gasification to convert into light gases the heavy hydrocarbons that form at typical biomass gasification temperatures (which are lower than coal gasification temperatures) and that would otherwise condense and cause operating difficulties down-stream; (iii) reforming of the recycle stream in the MTG design due in part to the higher methane production from biomass gasification com-pared to coal gasification.

As noted earlier, shortcomings of the BTL option include high feedstock costs and steep scale economies for the plant capital cost. These chal-lenges can be mitigated by coprocessing some biomass with coal (CBTL) (Blades et al., 2008 ; Tarka et al., 2009 ; Liu et al., 2011a ). Figure 12.20 (all colors of shading) shows a detailed design for a coal/biomass coprocess-ing system to make FTL fuels (CBTL) utilizing separate coal and biomass gasifiers. With different downstream processing steps, synthetic gas-oline could similarly be produced from coal and biomass (CBTG).

12.4.3.2 Performance Estimates

Results from a set of detailed and self-consistent designs and perform-ance simulations of coal and/or biomass conversion to FTL and MTG transportation fuels are presented in Table 12.15 . (Illinois #6 bitumin-ous is the coal type, and switchgrass is the biomass type.) The simula-tions utilize design assumptions for each unit operation (gasification, water gas shift, acid gas removal, FTL synthesis, MTG synthesis, etc.) that are consistent with performance that has been demonstrated in existing commercial applications for all except biomass gasification/tar cracking. For the latter, design assumptions are based on pilot-plant performance. The greenhouse gas emissions estimates include net life cycle emissions for synfuel production and consumption, including emissions associated with activities upstream of the conversion plant, such as coal mining and biomass growing, harvesting, and transporta-tion, as well as emissions downstream of the plant, including transport of the liquid products to refueling stations and combustion of the fuels in vehicles. The process of making synthetic gasoline has some effi-ciency benefit. For systems using only coal as feedstock and producing liquid fuels at a rate of 50,000 petroleum-fuel-equivalent barrels per day of liquids, Table 12.15 indicates that when making synthetic gas-oline (MTG) more of the input coal is converted to liquid fuel (and less to electricity) than for the FTL designs considered here. The result is an overall efficiency advantage of about 5 percentage points for MTG due to the intrinsically higher thermodynamic efficiency of converting syngas to liquids compared to converting it to electricity. There is only


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about 1.5 percentage points penalty in efficiency (with either MTG or FTL) when CCS is added. The penalty is primarily due to the added elec-tricity needed onsite to compress the captured CO 2 for transport and injection underground.

For systems described in Table 12.15 that use biomass it is assumed that the total biomass input is 1 Mt/yr (dry basis), a practical limit on the biomass delivery rate. For pure biomass systems (see Figure 12.20 ), this implies a liquid fuel production capacity of 4500–4600 bbl/day. The

Table 12.15 | Performance estimates for conversion of coal, biomass, and coal + biomass to FTL or MTG.

Process configuration >>>CTL-RC-V

CTL-RC-CCS

CTG-RC-V

CTG-RC-CCS

BTL-RC-V

BTL-RC-CCS

BTG-RC-V

BTG-RC-CCS

CBTL-RC-CCS

CBTG-RC-CCS

Coal input rate

As-received, metric t/day 24,087 24,087 20,869 20,869 – – 0 0 2562 2489

Coal, MW HHV 7559 7559 6549 6,549 – – 0 0 804 781

Biomass input rate

As-received metric t/day 0 0 0 0 3581 3581 3581 3581 3581 3581

Biomass, MW HHV 0 0 0 0 661 661 661 661 661 661

% biomass HHV basis 0 0 0 0 100 100 100 100 45 46

Liquid production capacities

LPG, MW LHV – – 309 309 – – 28 28 – 69

Diesel and/or Gasoline, MW LHV a 3159 3159 2913 2913 286 286 270 270 622 610

bbl/day crude oil products displaced (excl. LPG)

50,000 50,000 50,000 50,000 4521 4521 4630 4630 9845 10476

Electricity

Gross production, MW 849 849 545 545 77 77 78 78 157 145

On-site consumption, MW 445 555 419 509 35 46 46 58 104 134

Net exports, MW 404 295 126 36 42 31 32 20 53 11

ENERGY RATIOS

Liquid fuels out (HHV)/Energy in (HHV basis)

45.0% 45.0% 52.8% 52.8% 46.5% 46.5% 48.4% 48.4% 45.7% 50.2%

Net electricity/Energy in (HHV) 5.3% 3.9% 1.9% 0.6% 6.4% 4.7% 4.9% 3.1% 3.6% 0.7%

Total products (HHV)+ electricity/Energy in (HHV)

50.3% 48.8% 54.7% 53.4% 52.9% 51.2% 53.3% 51.5% 49.3% 51.0%

CARBON ACCOUNTING

C input as feedstock, kgC/sec 178 178 154 154 17 17 17 17 35 35

C stored as CO 2 , % of feedstock C 0 52 0 49 0 56 0 60 54 54

C in char (unburned), % of feedstock C

4.0 4.0 4.0 4.0 3.0 3.0 3.0 3.0 3.5 3.5

C vented to atmosphere, % of feedstock C

51.6 10.3 56.9 8.2 63.9 8.2 63.4 3.8 9.0 6.7

C in liquid fuels, % of feedstock C 34.1 34.1 39.1 39.1 33.1 33.1 33.7 33.7 33.7 36.1

C stored, 10 6 tCO 2 /yr (at 90% capacity)

0 9.54 0 7.80 0 0.96 0 1.03 1.98 1.95

Lifecycle GHG emissions, kgCO 2 -eq/GJ liquid fuels LHV b

207 101 195 100 7.9 –110 8.5 –125 3.2 1.9

GHGI c 1.71 0.89 1.76 0.97 0.063 – 0.95 0.066 – 1.07 0.029 0.018

a Finished diesel and gasoline for FTL cases (63.5% and 36.5% on LHV basis). Finished gasoline in the MTG case. b If all emissions are charged to gasoline and/or diesel fuels. c GHGI, the greenhouse gas emissions index, is the system wide life cycle GHG emissions for production and consumption of the energy products relative to emissions from a

reference system producing the same amount of liquid fuels and electricity. For FTL systems, the reference liquid fuels are a mix of gasoline and diesel from crude oil for which the average GHG emission rate is 91.6 kgCO 2 -eq/GJ LHV . For MTG systems the reference liquid fuels are gasoline and LPG having life cycle GHG emission rates of 91.3 kgCO 2 -eq/GJ LHV and 86.0 kgCO 2 -eq/GJ LHV , respectively. In all cases the reference system electricity is assumed to be from a new supercritical pulverized coal power plant for which the average GHG emissions rate is 830.5 kgCO 2 -eq/MWh e .

Source: Liu et al., 2011a ; Liu et al., forthcoming .


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overall efficiency for the biomass FTL design is modestly higher than that for the coal-FTL plant. For the MTG plant, however, the efficiency is lower than for the coal-only design due to the syngas compression required in the biomass design to raise the pressure of the syngas to that needed for methanol synthesis. (The gasification pressure is higher for coal than for biomass, so no syngas compressor is required in the coal-to-gasoline designs.) The need for reforming in the recycle loop also contributes to the reduced efficiency for biomass conversion to MTG relative to coal.

The carbon mitigation performance of alternative options is indicated by a greenhouse gas emissions index (GHGI), the system wide life cycle GHG emissions relative to emissions from a reference system producing the same amount of fuels and electricity. It is assumed that the reference system consists of equivalent crude oil-derived liquid fuels and electricity from a new stand-alone supercritical pulverized coal power plant venting CO 2 . The GHGI for each option is listed at the bottom of Table 12.15 and

summarized in Figure 12.22 . For coal conversion to FTL or MTG without capture of CO 2 , GHGI is 1.7 to 1.8 and GHGI is 0.9 to 1.0 with CCS. For biomass conversion, fuel cycle GHG emissions are < 0.07 when CO 2 is vented and strongly negative when CO 2 is captured and stored. For the designs coprocessing coal and biomass (see Figure 12.20 ), a mix (about 55% coal and 45% biomass, HHV basis) is chosen so that GHGI < 0.1. This GHGI constraint and the assumption of a biomass processing rate of 1 Mt/yr dry biomass imply that the liquid fuel production capacity is about 10,000 bbl/day in the CBTL and CBTG designs.

Biomass is a relatively scarce resource and the only carbon-bearing renewable energy source. Thus, the effectiveness of its use is an import-ant consideration. Figure 12.23 shows one measure of effectiveness: liters of low/zero-GHG gasoline-equivalent FTL or MTG fuel produced per dry tonne of biomass consumed. Shown for comparison is an esti-mate for future cellulosic ethanol (EtOH) made (without and with CCS) from switchgrass biomass via enzymatic hydrolysis. Not surprisingly, with the FTL and MTG systems that coprocess coal and biomass, the total liquid fuel produced per unit of biomass input is high (because of the coal coprocessing). In the case of pure biomass FTL and MTG and EtOH systems with CCS, it is assumed that the negative GHG emissions provide “room in the atmosphere” for using some conventional crude oil-derived fuels while maintaining overall zero net GHG emissions. The total low-C liquid fuel yields for the cellulosic ethanol production options would be comparable to the biomass-only FTL and MTG systems that vent CO 2 but less than half the yields of low carbon fuels realized for all FTL and MTG systems with CCS.

12.4.3.3 Cost Estimates

For each of the plant designs described in Table 12.15 , cost estimates are given in Table 12.16 . Costs are reported here in US 2007 $ as discussed in Section 12.2.2.3 .

Figure 12.22 | Values of GHGI for the synthetic fuel options described in Table 12.15 , along with the GHGI for future cellulosic-biomass ethanol technologies. See Table 12.15 , note (c) for defi nition of GHGI. For details on the cellulosic ethanol options see Box 12.3 and Liu et al., 2011a .

Figure 12.23 | Yields of low/zero net GHG emitting liquid fuels from biomass, liters of gasoline equivalent per dry tonne. For the biomass-only designs that incorporate CCS (BTL-RC-CCS, BTG-RC-CCS, and EtOH-CCS), life cycle GHG emissions are negative, leaving “room in the atmosphere” for some crude oil-derived fuel that can be used while keeping zero net GHG emissions for the biomass + crude oil-derived liquid fuels. Based on Liu et al., 2011a . See also Box 12.3 for a discussion of the cellulosic ethanol options.


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Specific capital costs for coal conversion without CCS range from US$81,000 per bbl/day to US$98,000 per bbl/day. Adding CCS involves a relatively small cost increment, since the primary additional cost is equip-ment for CO 2 compression. Specific costs for biomass conversion are con-siderably higher due largely to the much smaller scale of the conversion facility. Systems coprocessing coal and biomass are larger in scale than biomass-only systems, but smaller than the coal-only systems, which largely accounts for the intermediate level of specific capital costs.

Table 12.16 also shows both the levelized cost of fuel (LCOF) production and the crude oil price at which the FTL and MTG fuels would compete with petroleum-derived fuels when the price of GHG emissions is zero. For the coal-only plants, capital charges are the most significant production cost component, while for biomass-only facilities capital and feedstock are of comparable importance. For systems that vent CO 2 the breakeven oil price (BEOP) is in the range US$48–61/bbl for coal plants and US$126–133/bbl for biomass plants. For systems with CCS the BEOP is in the range

Table 12.16 | Capital cost and production cost estimates (US 2007 $) for conversion of coal, biomass, and coal+biomass to FTL or MTG.

Process configuration >>>CTL-RC-V

CTL-RC-CCS

CTG-RC-V

CTG-RC-CCS

BTL-RC-V

BTL-RC-CCS

BTG-RC-V

BTG-RC-CCS

CBTL-RC-CCS

CBTG-RC-CCS

Coal input rate, MW HHV 7559 7559 6549 6549 – – 0 0 804 781

Biomass input rate, MW HHV 0 0 0 0 661 661 661 661 661 661

Diesel and/or gasoline production, MW LHV 3159 3159 2913 2913 286 286 270 270 622 610

bbl/day crude oil products displaced, excl LPG 50,000 50,000 50,000 50,000 4521 4521 4630 4630 9845 10,476

Co-product LPG, MW LHV – – 309 309 – – 28 28 – 69

Net export to grid, MW 404 295 126 36 42 31 32 20 53 11

Plant capital costs, million US 2007 $

Air separation+ O2 and N2 compression 808 808 645 645 100 100 109 109 208 211

Biomass handling, gasifi cation, and gas cleanup 0 0 0 0 336 336 340 340 335 347

Coal handling, gasifi cation, and quench 1468 1468 1301 1301 0 0 0 0 226 189

water gas shift, acid gas removal, Claus/SCOT 849 849 589 598 59 59 89 89 158 162

CO 2 compression 0 67 0 59 2 14 2 14 22 22

F-T synthesis & refi ning or methanol synthesis 882 882 506 506 137 137 89 89 244 147

Naptha upgrading or MTG synthesis & refi ning 86 86 526 526 21 21 80 80 33 141

Power island topping cycle 35 27 0 0 0 0 0 0 7 0

Heat recovery and steam cycle 723 0 470 470 69 69 86 86 136 135

Total plant cost (TPC), million US 2007 $ 4852 4919 4038 4105 724 737 794 806 1369 1354

Specifi c TPC, US 2007 $/bbl/day 97,033 98,372 80,757 82,099 160,189 162,927 171,520 174,131 139,091 129,200

Liquids production cost, US 2007 $/GJ LHV (with zero GHG emissions price) a

Capital charges (at 14.38% of Total Plant Inv., TPI) 8.34 8.45 7.52 7.65 13.77 14.00 15.97 16.22 11.95 12.03

O&M charges (at 4% of TPC/year) 2.16 2.19 1.95 1.98 3.57 3.63 4.15 4.21 3.10 3.12

Coal (at 2.04 US$/GJ HHV , 55 US$/t, as-received) 4.87 4.87 4.58 4.58 0.00 0.00 0.00 0.00 2.63 2.60

Biomass (at 5 US$/GJ HHV ,94US$/t, dry) 0 0 0 0 11.56 11.56 12.24 12.24 5.31 5.41

CO 2 emissions charge 0 0 0 0 0 0 0 0 0 0

CO 2 disposal charges 0 0.52 0 0.46 0 1.38 0 1.41 0.94 0.90

Coproduct electricity (at 60 US$/MWh) –2.13 –1.56 –0.72 –0.21 –2.46 –1.81 –1.98 –1.26 –1.42 –0.29

Co-product LPG revenue (at 100 US$/bbl) – – –2.19 –2.19 – – –2.16 –2.16 – –2.16

Total, US 2007 $/GJ LHV 13.24 14.48 11.14 12.27 26.44 28.76 28.22 30.67 22.51 21.62

Total, US 2007 $/gallon gasoline equivalent 1.59 1.74 1.33 1.47 3.17 3.45 3.38 3.68 2.70 2.59

Breakeven oil price, US 2007 $/bbl b 61 67 48 53 133 145 126 137 111 96

Cost of avoided CO 2 , US 2007 $/t – 12.4 – 12.8 – 20.9 – 19.3 16.9 29.4

a See note (b) of Table 12.6 for fi nancial parameter assumptions. b The breakeven oil price (BEOP) is calculated assuming the LPG co-product is sold for its wholesale price assuming the crude oil price is US$100/bbl. The wholesale price of

LPG is determined as a function of crude oil price from a regression correlation of wholesale propane prices and refi ner crude oil acquisition costs in the United States (propane (US$/bbl) = 0.7212 * Crude acquisition cost (US$/bbl) + 5.2468). See Kreutz et al., 2008 for additional discussion of the BEOP calculation.

Source: Liu et al., 2011a ; Liu et al., forthcoming .


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US$53–67/bbl for coal plants, US$137–145/bbl for biomass plants, and US$96–111/bbl for plants that coprocess coal and biomass.

As shown in Figure 12.24 , when non-zero GHG emissions prices are considered, the relative economics of alternative process designs can be considerably different from those in Table 12.16 . At GHG emission prices above a modest US$10–20/tCO 2 -eq the –CCS variant of each option realizes a lower BEOP than the –V variant because the cost of CO 2 capture is low as a result of the production of a by-product stream of pure CO 2 as an intrinsic part of the design of gasification-based liquid fuels production. At GHG emission prices above US$65–75/tCO 2 -eq the biomass –CCS option realizes a lower BEOP than the correspond-ing coal –CCS option (with more than 10 times the output capacity), as a result of the strong negative GHG emission rates for the biomass with –CCS options.

12.4.4 Hydrogen from Non-petroleum Feedstocks for Transportation

Hydrogen production from fossil fuels, the subject of this section, is well-established commercially in petroleum refining, ammonia pro-duction, and other industries where hydrogen is needed as a chemical feedstock.

H 2 produced electrolytically from non-carbon energy sources (wind, solar) is more costly than projected costs of making H 2 with ultra-low GHG emissions from coal or natural gas with CCS (Williams, 2002 ). The higher cost is largely because electricity purchases account for the lar-gest share of total H 2 production costs with electrolysis. Wind and solar electricity are still more expensive than fossil fuel electricity today, des-pite reductions in costs for wind or solar electricity and escalations in

costs for construction of fossil energy conversion facilities. A key point is that electrolytic H 2 could plausibly be competitive as a transporta-tion fuel (via use in fuel cell vehicles) only if offpeak/low-cost electri-city (regardless of source) is used to make H 2 . But only a tiny fraction of transportation fuel demand (which globally is 1.6 times electricity generation) could be satisfied with H 2 from offpeak electricity (a small fraction of total electricity).

Hydrogen is not used as a transportation fuel today, but its attractions in this application include the potential for low emissions of local pollutants and of greenhouse gases, as well as the energy security benefits arising from being able to shift transportation from oil dependence. Such attrac-tions have made research on distribution and end-use systems for H 2 as a transportation fuel the focus of important government research and devel-opment programs in the United States, China, and elsewhere beginning in the 1990s. However, these R&D efforts have brought recognition that there are still major challenges to be overcome in H 2 delivery infrastruc-ture and end use before it can become a real option for the transportation sector (CASFHPU, 2004 ; Agnolucci, 2007 ; CARNFCHT, 2008 ). Here we limit our discussion to a review of technologies for hydrogen production.

Globally, natural gas is the most commonly used feedstock for hydrogen production (Consonni and Vigano, 2005 ; Rostrup-Nielsen, 2005 ), but hydrogen can also be made from coal (Chiesa et al., 2005 ; Kreutz et al., 2005 ), as is the predominant commercial practice in China. Hydrogen can also be produced from biomass in systems closely resembling those for coal conversion (Hamelinck and Faaij, 2002 ; Lau et al., 2002 ).

Figure 12.25 shows a simplified block flow diagram for hydrogen pro-duction from coal. Gasification technologies for production of CO and H 2 -rich synthesis gas from coal and biomass have been discussed in Section

Figure 12.24 | Breakeven oil prices (US 2007 $) as a function of GHG emission price for coal, biomass, and coal/biomass conversion to FTL or MTG. (See Table 12.6 , note (b) for fi nancial parameter assumptions. Also, electricity sales are assumed at the US average grid price plotted in Figure 12.10 .)


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12.4.3.1 . Gasification is followed by a water gas shift, after which sulfur species are removed to prevent poisoning of downstream catalysts. This presents a natural point for also removing CO 2 with little added capital cost. Acid gas removal using a physical solvent (e.g., methanol, as in the Rectisol process) would typically be used because of the elevated pres-sure of the gas mixture containing the acid gases. The captured sulfur is recovered from the solvent and converted, for sale or disposal, to elem-ental sulfur using the Claus/SCOT process. The captured CO 2 can be com-pressed for pipeline transport to an underground storage site. Following acid gas removal, the remaining hydrogen-rich stream is concentrated using pressure swing adsorption (PSA) technology to purity as high as 99.999%. Purge gases from the PSA, supplemented as needed by some syngas bypassing the PSA, are burned in the power island to provide the electricity needs of the plant and additional exportable power.

For hydrogen production from natural gas ( Figure 12.26 ), syngas can be produced using any of several different reforming technologies (Rostrup-Nielsen and Rostrup-Nielsen, 2002 ). The two most common, SMR and ATR, have been discussed in Section 12.4.1.1 . With natural gas conver-sion based on SMR ( Figure 12.26 , top), sulfur removal is not needed fol-lowing the water gas shift, since any sulfur present in the methane input to the plant has been removed prior to the SMR to avoid poisoning the SMR catalyst. If CO 2 is to be captured for storage, this would most effect-ively be accomplished using an acid gas removal system on the flue gases from the power island and the reformer furnace. This design enables maximum CO 2 capture, because all flue gases are collected before CO 2 removal. However, the low-pressure of the CO 2 in the flue gases requires using a chemical solvent (such as MEA) to effectively capture the CO 2 . The work to subsequently compress the captured CO 2 for pipeline trans-port will be higher than in the systems producing hydrogen using ATR, for which the CO 2 is available at a higher starting pressure. For a system using ATR ( Figure 12.26 , bottom), capture of CO 2 would take place after the water gas shift using a physical solvent, such as Rectisol.

Table 12.17 summarizes comparative mass and energy balance simu-lation results developed for this chapter for hydrogen production. It is based on detailed system designs represented in simplified form in Figures 12.25 and 12.26. For designs that capture CO 2 , the overall energy efficiency of coproducing hydrogen and electricity is 67% with coal and 74% with natural gas. The efficiency penalty for systems that

capture CO 2 compared with systems that vent the CO 2 is largest for the natural gas case using SMR ( Figure 12.26 , upper). This is due to the substantial heat required to liberate the dissolved CO 2 from the solvent used to capture it. The heat is provided as steam extracted from the power island, which reduces the on-site power generation significantly. Natural gas conversion using the ATR also requires some net import of electricity due to the substantial power requirements for air separation and CO 2 compression.

Capital and operating cost estimates for the systems described in Table 12.17 are provided in Table 12.18 using the same framework and component capital cost database as for systems described in Sections 12.4.3 and 12.6 . Hydrogen production costs using natural gas, despite the considerably lower capital cost intensity compared with coal designs, are nevertheless higher than for coal due to the much higher assumed feedstock prices. Production costs with natural gas are also higher in the CCS cases due to the need to purchase electricity to operate the facility rather than selling excess electricity to the grid.

The final row of Table 12.18 shows the avoided cost of CO 2 emissions when CCS is considered. The avoided cost for coal is modest (US$11/tCO 2 -eq) because capturing the CO 2 at these plants involves only add-ing a CO 2 compressor. The situation is similar for the natural gas system using ATR, but the avoided CO 2 cost is higher than for a coal-CCS design of comparable scale because the added cost includes that for acid-gas capture in addition to a CO 2 compressor. (The cost for acid gas removal is modest because only half as much CO 2 must be captured as in the coal case due to the lower carbon intensity of natural gas.) In the SMR design for natural gas, costs for the added equipment to capture dilute CO 2 from flue gases and compress it are charged against the CO 2 , lead-ing to relatively higher avoided costs.

Gasifica�on,Gas Cleaning

OxygenProduc�on

WaterGas Shi�

Acid GasRemoval

CO2compressor

PressureSwing

Adsorp�on

PowerIsland

Coal

Air

Oxygen

H2

Purge Gas

ExcessElectricity

CO2 to Storage

Figure 12.25 | Simplifi ed process diagram for H 2 production from coal with CO 2 capture.

Figure 12.26 | Simplifi ed process diagrams for H 2 production from natural gas via steam-methane reforming (top) or via autothermal reforming (bottom). When CO 2 is cap-tured for storage (as shown), import of electricity may be required to meet on-site needs. Without CO 2 capture, there can be net electricity exports to the grid from the facility.


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Table 12.17 | Mass and energy balances for hydrogen production for different feedstocks.

Feedstock >>> Coal a N. gas – SMR b N. gas – ATR b

CO 2 vented or captured >>>

Vent CCS Vent CCS Vent CCS

Power island technology >>>

Combined Cycle Steam Rankine Cycle

Coal input, as-received t/day

12,615 12,615

Coal input, MW HHV 3,817 3,817

Biomass input, as-received t/day

Biomass input, MW HHV

Natural gas input, t/day 5,561 5,561 5,519 5,519

Natural gas input, MW HHV

3,335 3,335 3,310 3,310

Hydrogen Production, MW LHV

2,083 2,083 2,083 2,083 2,083 2,083

Hydrogen Production, MW HHV

2,461 2,461 2,461 2,461 2,462 2,462

Electricity

Gross production, MW 424.8 424.8 217.5 85.6 262.0 262.0

On-site consumption, MW 272.4 349.2 27.2 103.4 220.4 274.3

Net export to grid, MW 152.4 75.6 190.3 -17.8 41.6 -12.3

ENERGY RATIOS (HHV basis)

H 2 out / energy in 64.5% 64.5% 73.8% 73.8% 74.4% 74.4%

net electricity / energy in 4.0% 2.0% 5.7% -1.4% 1.3% -0.4%

H 2 + electricity / energy in 68.5% 66.5% 79.5% 72.4% 75.6% 74.0%

CARBON ACCOUNTING

C input as feedstock, kgC/sec

89.5 89.5 47.7 47.7 47.3 47.3

C stored as CO 2 , % of feedstock C

0.0 91.2 0.0 90.0 0.0 82.8


0.8 0.8 0.0 0.0 0.0 0.0

C vented to atmosphere, % of feedstock C

99.2 8.0 100 9.9 100 17.1

C stored, MtCO 2 /yr (90% capacity factor)

0.0 8.5 0.0 4.5 0.0 4.1

Lifecycle GHG emissions

Net emissions, kgCO 2 -eq/GJ H 2 LHV

163 19.1 84.3 10.8 83.6 16.1

GHGI c 1.74 0.22 0.86 0.14 1.03 0.21

a Results based on performance simulations of Chiesa et al., 2005 . b Results based on performance simulations of Zhang, 2005 . c GHGI, the greenhouse gas emissions index, is the system wide life cycle GHG emissions for production of H 2 and electricity relative to emissions from a reference system produ-

cing the same amount of H 2 and electricity. The reference system consists of large-scale centralized H 2 production by steam reforming of natural gas, with lifecycle emissions of 9.22 kgCO 2 -eq/kgH 2 (NRC, 2004 ), plus electricity from a supercritical pulverized coal power plant with GHG emissions rate of 830.5 kgCO 2 -eq/MWhe.

d In the GHGI calculation, net electricity consumed in these process designs is charged 830.5 kgCO 2 -eq/MWhe. All other designs in this table have net exports of electricity.


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Table 12.18 | Cost estimates (US 2007 $) for hydrogen production systems described by Table 12.17 .

Feedstock >>> Coal N. gas – SMR N. gas – ATR

CO 2 vented or captured >>> Vent CCS Vent CCS Vent CCS

Coal input rate, MW HHV 3817 3817

Biomass input rate, MW HHV

Natural gas input rate, MW HHV 3335 3335 3310 3310

hydrogen production rate, MW LHV 2083 2083 2083 2083 2083 2083

Net export to grid, MW 152.4 75.6 190.3 -17.8 41.6 -12.3

Plant capital costs, million US 2007 $ a

Air separation unit + O 2 , N 2 , air compressor

404 404 0.0 0.0 79 79

Biomass handling, gasifi cation, gas cleanup

0.0 0.0 0.0 0.0 0.0 0.0

Coal handling, gasifi cation, and quench

791 791 0.0 0.0 0.0 0.0

Reforming (SMR or ATR) 0.0 0.0 737 737 244 244

WGS, acid gas removal, Claus/SCOT b 581 581 161 161 222 264

MEA system for SMR case (CO 2 removal)

0.0 0.0 0.0 135 0.0 0.0

CO 2 compression 9.3 62 0.0 48 0.0 38

PSA section (including H2 compression)

83 83 34 34 76 58

Power island topping cycle 62 62 0.0 0.0 0.0 0.0

Heat recovery and steam cycle 139 139 110 79 222 237

Total plant cost (TPC), million US 2007 $

2067 2120 1042 1194 844 920

US 2007 $/kW HHV of input feedstock 542 555 312 358 255 278

Levelized hydrogen cost with no carbon emission price, US 2007 $/GJ LHV c

Capital charges 5.4 5.5 2.7 3.1 2.2 2.4

O&M charges 1.4 1.4 0.7 0.8 0.6 0.6

Coal (at 2.04 US$/GJ, HHV; 55 US$/t, as-rec’d)

3.7 3.7 0.0 0.0 0.0 0.0

Biomass (at 5 US$/GJ, HHV; 93.7 US$/t, dry)

0.0 0.0 0.0 0.0 0.0 0.0

NG (at 5.11 US$/GJ, HHV) 0.0 0.0 8.2 8.2 8.1 8.1

CO 2 transportation and storage 0.0 0.7 0.0 0.4 0.0 0.4

Electricity sales or purchase (at 60 US$/MWh)

-1.2 -0.6 -1.5 0.1 -0.3 0.1

Total hydrogen cost, US 2007 $/GJ LHV

9.3 10.8 10.1 12.7 10.6 11.7

Cost of avoided CO 2 , US 2007 $/tCO 2e d

– 11 – 47 – 17

a Component costs are based on Liu et al., 2011a, except for: SMR (Simbeck, 2004 ); ATR (Simbeck and Wilhelm, 2007 ); MEA system (Kreutz et al., 2005 ; Woods et al., 2007 ). b In the case of N.gas SMR with CCS, only the WGS cost is included in this line since acid gas removal is done via MEA (separate cost line) and no sulfur treatment via Claus/SCOT

is needed. c See note (b) of Table 12.6 for fi nancial parameter assumptions. d Levelized H 2 production cost for system with CCS minus that for system without CCS, divided by the difference in system-wide life cycle emissions of CO 2 -eq/GJ LHV of H 2 (given in

Table 12.17 ).


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Figure 12.27 plots hydrogen production costs as a function of the price of greenhouse gas emissions. Coal provides the least costly low-GHG hydrogen (US$10–12/GJ LHV ) in the system with CCS for a GHG emission price above US$10/tCO 2 -eq.

An important final comparison is between the costs of hydrogen pro-duction with CCS and those for low-GHG liquid fuels. For GHG emission prices from US$0–100/tCO 2 -eq, the lowest production costs for low-GHG liquid fuels are with systems that coproduce liquids and power (see Section 12.6 ). Liquid fuel costs from such systems are $US15–17/GJ LHV depending on the GHG emissions price (see Figure 12.36 ). This is higher than the US$10–12/GJ LHV estimated for hydrogen ( Figure 12.27 ). But use of hydrogen for transportation will require new delivery and refueling infrastructures, as well as new vehicle technologies, unlike for petroleum-like liquid fuels.

Cost estimates in the literature for new infrastructure in the United States delivering H 2 from centralized production facilities to vehicle fuel tanks are much higher than for new infrastructure for liquid fuels. Published hydrogen infrastructure cost estimates include US 2007 $14–16/GJ LHV (Ogden et al., 2004 ), US 2007 $9–20/GJ LHV (Mintz et al., 2002 ), and US 2007 $44/GJ LHV (Simbeck, 2003 ). Compared to these costs, the new-infrastructure costs for delivery of liquid fuels, particularly petroleum-like fuels, would be small. Moreover, in the industrialized countries, the investment in a full liquid fuel infrastructure has already been made. Thus, when production and delivery infrastructure costs are considered together, delivered hydrogen costs would be significantly higher than delivered costs for liquid fuels.

Beyond questions around fuel delivery infrastructure, it remains uncer-tain when the cost of hydrogen fuel cell vehicles, which have been the focus of considerable development efforts over the past two dec-ades, can be reduced to competitive levels. One study (IEA, 2009a ) estimates that in the near term the GHG emissions price needed to induce by market forces a shift to hybrid fuel cell vehicles is more than US$1000/tCO 2 -eq when the crude oil price is US$60/bbl and almost US$800/t with US$120/bbl of crude oil. The major technical challenges for fuel cell vehicles are difficulties of onboard H 2 storage due to its low volumetric energy density and high projected costs for fuel cell engines (in part due to platinum requirements). These challenges may not be insurmountable, but overcoming them will require time and sustained large government investments in R&D (CARNFCHT, 2008 ). 12 Thus, it is likely to be many decades before H 2 fuel cell vehicles will be in a position to make significant contributions toward reducing GHG emissions.

12.5 Clean Household Fuels Derived from Non-petroleum Feedstocks

Studies have shown that human welfare, as measured by the Human Development Index (HDI), increases with diminishing returns as the level of modern energy services provided increases (WEA, 2004 ). The HDI increase is especially large for provision of the first increments of modern energy carriers to satisfy basic needs such as cooking and heating, for which demand is very inelastic (cooking and boiling water are essential for survival). There is wide recognition of the importance of the role that electricity plays in economic development and the fact that more than a billion people do not have access even to the minimal amounts of elec-tricity required to satisfy basic needs. Similarly, it is recognized that there are nearly three billion people who cook their food today using trad-itional open fires inside their homes, suffering considerable health dam-ages in the process (see Hutton et al., 2006 and Chapters 4 , 17 , and 19 ).

Fluid hydrocarbon fuels offer a much cleaner means of providing cook-ing services than solid fuels (Smith, 2002 ). Moreover, fluid fuels enable much higher efficiency (Dutt and Ravindranath, 1993 ) and control-lability than cooking with solid fuels. 13 Historical real data confirm the gains from efficiency and controllability ( Figure 12.28 ). Such gains along with consideration that a shift to cooking with clean fuels leads to demands on a global basis that are relatively small compared to energy demands for other purposes, means that a relatively small amount of fluid fuel would be sufficient to replace all current solid fuel used for cooking.

12 Waning enthusiasm for addressing these challenges was evident in the Obama Administration’s proposed 2010 Department of Energy (DOE) budget, which included a cut in the federal hydrogen fuel cell research and deployment budget by more than two thirds, eliminating funds for the H 2 fuel cell vehicle program and market transformation programs.

Figure 12.27 | Levelized hydrogen production costs as a function of GHG emissions price. (See Table 12.6 , note (b) for fi nancial parameter assumptions. Also, electricity sales are assumed at the US average grid price plotted in Figure 12.10 .) Source: based on Simbeck, 2004 ; Simbeck and Wilhelm, 2007 ; Liu et al., 2011a .

13 Consider LPG stoves. Not only are they much more energy-effi cient than biomass stoves, but also an LPG stove can be instantly turned on and off with the demand for cooking services, whereas a biomass stove must be started up long before cooking begins and continue burning long after cooking stops. Of course, the continued burn-ing of biomass after a meal is cooked in the evening may often be for lighting. This implies that, if LPG is to be substituted for biomass for cooking, this cooking fuel switch should often be accompanied by the introduction of alternative means for lighting.


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For perspective, suppose that all three billion people currently using solid fuels for cooking were instead to use liquefied petroleum gas (LPG) at an estimated average needed rate of 25 kg/capita/yr (36 W/capita). 14 The total annual requirement would be 3.4 EJ/yr, or 1.3% of current total global oil and gas consumption.

A shift from solid to fluid fuels for cooking would yield substantial public benefits in terms of improved public health and time saved not spent collecting solid fuels, which would make time available to pursue edu-cational and other opportunities (see Chapter 4 ). Another benefit would be reduced deforestation, to the extent that some biomass collected for cooking is removed unsustainably from forests.

Such considerations have led to proposals for concerted global efforts to replace solid cooking fuels with clean fluid fuels worldwide (Goldemberg et al., 2004 ; IEA, 2006 ; WHO, 2006 ; GACS, 2011 ).

Concerns about rising costs of and overdependence on petroleum imports have created interest in alternatives to petroleum-derived fluid cooking fuels such as kerosene and LPG. This section discusses produc-tion systems for expanding clean fluid cooking fuel supplies. It considers the use of synthetic fluid fuels (synthetic LPG and DME) derived via gas-ification of coal and/or biomass, without and with carbon capture and storage. Coal and biomass are the most widely available feedstocks in regions where solid fuels are now used for cooking. DME as a cooking

fuel could also be made from natural gas (Naqvi, 2002 ). The growing optimism that shale gas might prove to be widely available (see Section 12.7.2.2 ) suggests also giving close attention to DME derived from nat-ural gas for cooking, though this topic is not covered here.

12.5.1 Dimethyl Ether from Coal

Dimethyl ether is a colorless gas at ambient temperature and pressure, with a slight ethereal odor. It requires mild pressurization, similar to that required for LPG, to be stored as a liquid. It burns with a clean blue flame over a wide range of air/fuel ratios. It can be used as a die-sel engine fuel (Semelsberger et al., 2006 ) or blended with LPG for use as a household or commercial sector fuel. In the latter application, the focus of the discussion here, the DME can be blended up to about 25% by volume without the need to change end-use combustion equipment. Table 12.19 compares some physical properties of DME with those of the two main constituents of LPG.

Until recently, DME was used primarily as an aerosol propellant in hair sprays and other personal care products and was produced globally at a rate of about 150,000 t/yr (Naqvi, 2002 ).This production level has increased dramatically in the past few years, with the added DME being used primarily as an LPG supplement for household use. The increase has been most substantial in China, where an estimated total DME production capacity of nearly 14 Mt/yr from coal have recently commenced produc-tion or construction, and a comparable amount of additional capacity is at various planning, feasibility, or engineering stages (Zheng et al., 2010 ).

Production of DME from synthesis gas is similar in many respects to syn-thesis of methanol, a well-established commercial process. In fact, a key step in the synthesis process is catalytic synthesis of methanol, followed

Figure 12.28 | Per capita energy use rate for cooking in the early 1980s. For both wood stoves and stoves burning high-quality energy carriers, the per capita energy use rate is in Watts; for wood fuel, the rate is also in t/yr of dry wood. (Assuming 1 tonne = 18 GJ, 1 t/yr = 570 Watts). Source: Goldemberg et al., 1985 .

14 In a spreadsheet accompanying the World Health Organization paper (Hutton et al., 2006 ) that was made available to the authors, estimates were developed by this WHO group of the LPG that would be required to replace direct use of biomass for cooking in regions throughout the world. Worldwide the average per capita amount of LPG needed annually was estimated to be 24.6 kg, but this rate varies from an average of 14.3 kg for Africa, to 25.6 kg for the region including India, to 29.3 kg for the region including China, to 47.0 kg for the region including Brazil.


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by dehydration of methanol to form DME: 2CH 3 OH ↔ CH 3 OCH 3 + H 2 O. Methanol can be synthesized at one plant location and transported to another location where dehydration can be done. This is how most DME has historically been produced. Alternatively, methanol and dehydration plants can be integrated at a single facility. Moreover, technology is now available for a single-step synthesis of DME from syngas: some metha-nol synthesis catalyst and some dehydration catalyst are used together in the same reactor so that methanol is dehydrated as it forms. The single-step synthesis chemistry can be represented as follows: 3CO + 3H 2 ↔ CH 3 OCH 3 + CO 2 . This approach gives rise to higher yields than the traditional two-step process and so is likely to be the technology of choice in the future.

Figure 12.29 illustrates one possible process arrangement for convert-ing coal to DME. Coal is gasified in oxygen to produce a raw syngas that is cooled and cleaned before having its H 2 :CO ratio adjusted in a water-gas-shift reactor (using a sulfur-tolerant catalyst) to an opti-mum value for subsequent catalytic synthesis of DME. The synthesis step can use a recycle of unconverted gas to increase DME production or a single-pass of the gas through the synthesis reactor (“once-through” design). The unconverted gas can be burned in a gas turbine/steam tur-bine combined cycle to generate coproduct electricity. Removal of CO 2 is an essential part of the DME production process, since excess CO 2 reduces the efficiency of the downstream synthesis step and would also necessitate larger downstream equipment. The captured CO 2 can be released to the atmosphere or compressed for pipeline transport and underground storage.

Celik et al. ( 2004 ), building on work by Larson and Ren ( 2003 ), present detailed process designs and production costs for large-scale single-step “once-through” DME synthesis systems starting with coal as the feedstock. Designs with and without CCS were analyzed ( Table 12.20 ). For the design labeled “UCAP” (shorthand for “upstream CO 2 capture”), CO 2 for storage is captured upstream of the DME synthesis area (as depicted in Figure 12.29 ). Only about 30% of the carbon in the coal feedstock is captured in this case. Nearly 70% of the carbon is released to the atmosphere as flue gas from the power island and when the product DME is burned. For the systems labeled DCAP (shorthand for “downstream plus upstream CO 2 capture”), additional CO 2 is removed by subjecting the unconverted syngas after synthesis to varying levels

of water gas shift before the power island. In the case with the highest amount of CO 2 capture (DCAP-3), nearly 80% of the carbon in the coal is captured.

The GHGI, defined in Table 12.20 note (b), without CCS is 1.3. The UCAP design reduces this to 0.94. With more aggressive CCS (DCAP designs), greenhouse gas emissions can be reduced to less than 50% of the ref-erence system emissions. The cost of avoided CO 2 emissions relative to the VENT design are modest for the UCAP case (last row, Table 12.20 ), since the cost of capture is an intrinsic part of the DME production process regardless of whether CO 2 storage is contemplated. Costs of avoided CO 2 emission are higher for the DCAP designs because the cost for the additional CO 2 capture equipment is fully charged to CO 2 capture.

The added capture equipment also leads to higher DME produc-tion costs. For US conditions, with the financial assumptions noted in Table 12.20 (note d), the VENT design produces DME at an estimated cost of US$423/tLPG-eq, corresponding to a breakeven crude oil price (BEOP) of about US$40/bbl. The BEOP is only slightly higher for the UCAP case, but significantly higher for the DCAP cases, reaching US$81/bbl for the DCAP-3 design. Larson and Yang ( 2004 ) estimate that costs of DME production in China today might be 15% lower than these esti-mates for US conditions.

12.5.2 Synthetic LPG from Coal and/or Biomass

Clean cooking fuels can also be produced from coal and/or biomass via the F-T or methanol-to-gasoline processes described in Section 12.4.3 . The designs discussed there are for production of synthetic transportation fuels as the primary products, but significant quan-tities of C3 and C4 hydrocarbons are produced as intermediate or final products. In either system, these lighter hydrocarbons can be separated from the heavier transportation fuel products for sale as synthetic LPG.

For the design of the F-T systems described earlier, it was assumed that the light hydrocarbon fraction was consumed internally as a component of the fuel gas for the power island. Alternatively, the lighter fraction could have been separated as an additional coproduct. The raw syn-thesis product can contain as much as 20% by weight of C3 and C4 compounds that constitute synthetic LPG.

CoalPrepara�on

Gasifica�onGas cooling& clean-up

WaterGas Shi�

Acid GasRemovalOxygen

Produc�on

DMESynthesis

PowerIsland

Separa�on

coal

air

Electricity

DME

CO2

H2S, COS

Figure 12.29 | Process steps for DME production from coal.

Table 12.19 | Physical properties of DME, propane, and butane.

DME Propane Butane

Boiling point (°C) –24.9 –42.1 –0.5

Vapor pressure ant 20°C (bar) 5.1 8.4 2.1

Liquid density at 20°C (kg/m 3 ) 668 501 610

Lower heating value (MJ/kg) 28.4 46.4 45.7

Auto-ignition temperature at 1 atm pressure (°C)

235 – 350 470 365

Flammability limits in air (vol %) 3.4 – 17 2.1 – 9.4 1.9 – 8.4

Source: Larson and Yang, 2004 .


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Table 12.20 | Performance and cost (US 2007 $) estimates for DME production from coal with different levels of CCS. “UCAP” refers to designs with CO 2 removal upstream of DME synthesis (as in Figure 12.29 ). “DCAP” refers to designs that additionally capture some CO 2 downstream of synthesis. Three alternative downstream capture designs are considered. See Celik et al. ( 2004 ) for details.

No CCS With varying levels of CO 2 capture

Vent UCAP DCAP-1 DCAP-2 DCAP-3

Coal input, MW LHV 2203 2203 2203 2203 2203

DME output, MW LHV 600 600 600 600 600

Gross power production, MW 628 628 589 590 586

Net power export, MW 490 469 367 365 353

Fraction of coal LHV converted to DME 0.272 0.272 0.272 0.272 0.272

Fraction of coal LHV converted to net power 0.223 0.213 0.167 0.166 0.160

Total effi ciency (LHV basis) 49.5 48.5 43.9 43.8 43.2

Plant carbon balance, tC/hr

Input as coal 199.7 199.7 199.7 199.7 199.7

Buried as char 2.0 2.0 2.0 2.0 2.0

Captured as CO 2 0 57.5 143.5 147.6 156.4

Total C captured, % of coal C 0 30% 73% 75% 79%

System life cycle GHG emissions a

kgCO 2 -eq/GJ DME LHV 349 251 105 98 84

GHGI b 1.27 0.94 0.46 0.43 0.38

Costs

Overnight Installed Capital (million US 2007 $) c 1,306 1,198 1,269 1,308 1,317

Levelized DME production cost (US 2007 $/GJ LHV ) d

Capital, US$/GJ LHV 13.85 12.70 13.46 13.87 13.96

O&M, US$/GJ LHV 3.45 3.17 3.35 3.46 3.48

Coal, US$/GJ LHV 7.49 7.49 7.49 7.49 7.49

CO 2 transport and storage, US$/GJ LHV 0 1.56 3.72 3.84 4.05

Electricity sales, US$/GJ LHV –13.61 –13.03 –10.19 –10.14 –9.80

Total (US 2007 $/GJ LHV ) 11.18 11.89 17.83 18.52 19.18

Total (US 2007 $/tDME) 317 337 506 526 544

Total (US 2007 $/tLPG-eq) 514 546 820 852 882

Breakeven crude oil price (US 2007 $/bbl) e 50 54 85 88 92

Cost of CO 2 captured (US 2007 $/tCO 2 avoided) f 7.3 27 29 30

a Including emissions associated with coal mining and delivery (1.024 kgC-eq/GJ COAL,LHV ), emissions at the conversion plant, and emissions from combustion of the DME. b GHGI, the greenhouse gas emissions index, is the system wide life cycle GHG emissions for production of DME and electricity relative to emissions from a reference system. The

reference system consists of LPG from conventional sources, with estimated lifecycle emissions 86 kgCO 2 /GJ LHV , plus electricity from a supercritical pulverized coal power plant with GHG emissions rate of 830.5 kgCO 2 -eq/MWhe.

c Converted from US 2003 $ in Celik et al. ( 2004 ) to US 2007 $ using the Chemical Engineering Plant Cost Index. d Assuming 7% interest during construction, 15% per year capital charge, 80% capacity factor, annual O&M cost of 4% of overnight capital cost, coal cost of US$2.04/GJ, electri-

city revenue of US$60/MWh (the 2007 US average generator sale price), and CO 2 transport and storage cost of US$15/tCO 2 , and zero GHG emissions price. e A linear regression of monthly wholesale propane price and refi ner acquisition cost for crude oil in the United States for the period October 1990 to March 2009 US EIA, 2009b

gives the following correlation: Propane price (US$/gallon) = 0.0168 * (US$/bbl oil ) + 0.133 [R 2 = 0.92]. Assuming the propane density given in Table 12.19 , the breakeven oil price in US$/bbl is (US$/t propane – 70.13) / 8.87. We assume this correlation holds equally for LPG.

f This is the difference in US$/GJ LHV levelized cost of DME production with CO 2 capture and the VENT design divided by the difference in system-wide life cycle emissions of CO 2 -eq/GJ LHV of DME.


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For the MTG systems described in Section 12.4.3 , a synthetic LPG coproduct is produced, equivalent to about 10% of the synthetic gas-oline output (LHV energy basis, see Table 12.15 ). Systems such as this one might contribute to addressing the challenge of providing universal access to clean cooking fuels, as discussed in the next section.

12.5.3 Co-providing synthetic cooking and transport fuels in the context of a carbon mitigation policy

Increasing conventional LPG use to meet the basic cooking fuel needs of those currently cooking with solid fuels would make a relatively small total energy impact and GHG emission impact. As such, one might argue that meeting the critical energy needs of the energy poor should not be constrained by a requirement that access to energy be provided in a manner consistent with simultaneously mitigating the climate change impacts of the cooking fuel consumed.

In some cases, however, a strong carbon mitigation policy may actu-ally improve the prospects for providing clean energy to satisfy basic cooking needs. This judgment is illustrated here by considering the technology ( Table 12.21 ) and economics ( Figure 12.30 ) of six MTG process designs. Figure 12.30 shows that for five of these systems the economics improve with GHG price. These five systems (four of which involve CCS 15 and four of which involve biomass) all offer substan-tial reductions in GHG emission rates relative to the crude oil derived products (CODP) and PC-V coal electricity displaced (see final column in Table 12.21 ). The two pure biomass designs in this table have been

discussed in Section 12.4.3 . The other four designs, which involve the generation of electricity as a major co-product, are described in Section 12.6 .

Key observations can be made about the relative economics of the six MTG options:

CTG-PB-CCS is a coal-only option offering a 44% reduction in sys- •tem-wide GHG emissions relative to the CODP and PC-V electricity displaced. It offers less costly gasoline than the GHG-emissions-intensive CTG-PB-V for GHG emissions prices greater than US$20/tCO 2 -eq.

CTG-PB-CCS and CBTG1-PB-CCS (an option with biomass account- •ing for 10% of input energy offering a 60% reduction in system-wide

15 For all CCS options it is assumed that the captured CO 2 is compressed to 150 bar, transported 100 km, and stored 2 km underground in a deep saline formation via wells for which the maximum injectivity is 2500 tonnes per well per day.

Table 12.21 | Key features of alternative process designs for producing synthetic gasoline and LPG from coal and/or biomass.

Process description a

Output capacities LPG output (10 6 kg/y)

TPC (millionUS 2007 $)

Biomass fraction (HHV)

Biomass input

(10 6 dt/y)

CO 2 storage

rate (10 6 t/y)

CCS primary energy

penalty (%)

GHGI b Gasoline (bbl/day)

Electricity (MW e )

CTG-PB-V 32,579 959 125 4,110 0 0 0 – 1.37

CTG-PB-CCS 32,579 760 125 4,310 0 0 10.2 9.8 0.56

CBTG1-PB-CCS 32,579 782 123 4,526 0.1 0.99 10.3 9.5 0.40

CBTG-PB-CCS 11,582 292 42.2 2,086 0.29 1.0 3.7 8.9 0.098

BTG-RC-V 2,315 16.0 8.72 475 1.0 0.5 0 – 0.066

BTG-RC-CCS 2,315 10.2 8.72 482 1.0 0.5 0.513 5.7 – 1.07

a CTG = coal to gasoline+LPG; CBTG = coal+biomass to gasoline+LPG; CBTG1 = coal+biomass to gasoline+LPG with reduced biomass fraction; BTG = biomass to gasoline+LPG; PB = partial bypass of syngas around synthesis island for use in power island; RC = recycle of unconverted syngas to maximize liquids production; V = venting of CO 2 ; CCS = carbon capture and storage.

b GHGI, the greenhouse gas emissions index, is the system wide life cycle GHG emissions for production and consumption of the energy products relative to emissions from a reference system producing the same amount of liquid fuels and electricity. The reference system consists of electricity from a stand-alone new supercritical pulverized coal power plant venting CO 2 plus equivalent crude oil-derived liquid fuels. For details, see Table 12.15 , note (c).

Figure 12.30 | Breakeven crude oil price (BEOP) as a function of the GHG emissions price for the MTG options described in Table 12.21 . (See Table 12.6 , note (b) and Table 12.16 , note (b) for fi nancial parameter and other assumptions. Electricity sales are assumed at the US average grid price plotted in Figure 12.10 .)


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GHG emissions) are both competitive as gasoline providers when crude oil is US$70/bbl at zero GHG emissions price.

CBTG1-PB-CCS offers less costly gasoline than both CTG-PB-V •and CTG-PB-CCS for GHG emissions prices greater than US$50/tCO 2 -eq.

CBTG-PB-CCS is an option with biomass accounting for 30% of •input energy offering a 90% reduction in system-wide GHG emis-sions. It could provide gasoline at the least cost of all the options shown at GHG emissions prices greater than about US$100/tCO 2 -eq.

BTG-RC-CCS is an option for which biomass accounts for 100% of •input energy offering strongly negative GHG emissions. It could pro-vide less costly gasoline than gasoline derived from US$90/bbl of crude oil at GHG emissions prices greater than US$62/tCO 2 -eq.

BTG-RC-V can provide less costly gasoline than gasoline derived •from US$90/bbl of crude oil at GHG emissions prices greater than US$106/tCO 2 -eq.

BTG-RC-CCS can provide less costly gasoline than BTG-RC-V at GHG •emissions prices greater than US$23/tCO 2 -eq. 16

Analysis in the World Energy Outlook 2009 (IEA, 2009b ) is helpful in understanding the relative competiveness of alternative technologies in Table 12.21 in a world with high oil prices and policies that constrain GHG emissions. The Outlook considers the current situation regarding carbon trading and analyzes prices for crude oil and for GHG emissions for a world on a path toward ultimate stabilization of GHG concentrations in the atmosphere at 450 ppmv. The IEA estimates for its 450 ppmv stabil-ization scenario that: (i) the world oil price would be stable during 2020–2030 at US$90/bbl (considerably lower than the oil price in this period for the IEA Reference Scenario), (ii) if there were separate emissions trad-ing regimes for OECD+ countries and for other major economies (China, Russia, Brazil, South Africa, Middle East), the GHG emissions price would rise from US$50/t to US$110/t in OECD+ countries between 2020–2030 and would reach US$65/t in other major economies by 2030; and (iii) if there were a single global carbon market for emissions trading, the glo-bal GHG emissions price would be US$70/t by 2030.

Thus under such carbon policy constraints, well before 2030, the proc-esses of CTG-PB-CCS and CBTG1-PB-CCS would become cost competi-tive in both OECD+ and Other Major Economies. Also, CBTG-PB-CCS technologies would be cost-competitive in the post-2030 time frame

in OECD+ countries. Early experience, prior to 2030, with widespread deployment of CTG-PB-CCS and CBTG1-PB-CCS technologies in coal-rich regions such as the United States and China would establish in the market all the technological components needed for subsequent deploy-ment of CBTG-PB-CCS in coal-rich regions and BTG-RC-CCS in coal-poor but biomass-rich regions. The economic prospects for BTG-RC-V are not auspicious, although the BTG-RC-CCS option is prospectively economic-ally viable in coal-poor but biomass-rich regions in the period after 2030 where there is adequate CO 2 storage capacity and emissions trading opportunities. For example, when the crude oil price is US$90/bbl, when coal coprocessing is not a realistic option, and the emissions trading price is US$70/t the BTG-RC-CCS option would be highly competitive.

12.5.3.1 Two Thought Experiments

Two thought experiments are presented here, one for China (a coal-rich region) and one for Africa (a biomass-rich but coal-poor region). In this experiment, both regions are under a carbon policy constraint. The discussion focuses on the strategic linkages between providing fuels/electricity for transportation on the one hand, versus providing LPG to satisfy basic human needs for cooking on the other hand.

China Why China? China is a good candidate for early deployment of CTG-PB-CCS and CBTG1-PB-CCS technologies to make simultaneously liquid fuels for transportation and LPG for cooking. There are many reasons:

China is a coal-rich country, accounting for more than 70% of coal •use by developing countries in 2007 (IEA, 2009b ).

China has a strong coal gasification-based chemical process indus- •try (making gasoline is very much like making chemicals via coal gasification).

China already has experience with CTG technology. A demonstra- •tion plant producing 2600 barrels of gasoline per day came online in 2009, built by Uhde for the Shanxi Jincheng Anthracite Coal Mining Co. Ltd. This plant uses the ExxonMobil methanol-to-gasoline pro-cess and is coupled to a fluidized bed hard coal gasifier and a plant for making methanol from coal via gasification.

Potential demand for clean cooking fuels in China is huge. Hundreds •of millions of Chinese still cook with solid fuels.

As a large food producer, China has substantial crop residue resources •that could be used for energy purposes. 17

16 This breakeven GHG emissions price for shifting from the V to the CCS variant of the BTG-RC option is higher than the US$20/tCO 2 -eq indicated for this pair of options in Figure 12.24 because in the present case the assumed biomass input rate is half as large.

17 Prospective crop residue supplies in China have been estimated by Li et al. ( 1998 ), who estimate that crop residue supplies potentially available for energy applications in China in 2010 were 376 million dry t/yr.


954

China is a good candidate for pursuing synthetic transportation fuels •derived from secure domestic coal and biomass supplies because its domestic oil supplies are scarce and its demand for liquid fuels for transportation is rapidly growing.

The coproduction approach to CCS, which offers low energy and water •penalties and low capture costs, may be perceived as an attractive approach for reducing coal-related GHG emissions in China.

The thought experiment : To illustrate the possibilities for early action for coal-based technologies, suppose that in China in the period prior to 2030 enough MTG plants are built to provide LPG sufficient to meet the needs of the 1.06 billion people that were cooking with solid fuels as of 2001. 18

Assumptions : It is assumed that during this period the carbon policy in China becomes sufficiently stringent to warrant deployment of both CTG-PB-CCS and CBTG1-PB-CCS systems. Furthermore, it is assumed that a mix of these two technologies is deployed such that on average gasoline, LPG, and electricity are provided at one half the GHG emis-sion rate of the CODP and PC-V electricity displaced. This implies that 62% of the capacity would be CTG-PB-CCS plants and 38% would be CBTG1-PB-CCS plants (so that, on average, biomass accounts for 3.8% of primary energy input).

Findings : The system-wide features of this combination of plants would yield 100% satisfaction of the need for clean cooking fuels and a 50% reduction in GHG emissions relative to the energy products displaced. In addition, the features would be the following:

the required investment (Total Plant Cost (TPC)) would be US$1.1 •trillion (US 2007 $);

synthetic gasoline would be produced at a rate of 13.5 EJ/yr (322 •Mtoe/yr or 66% of projected transportation energy demand in China in 2030 (IEA, 2009b );

electricity would be produced at a rate of 1516 million MWh/yr (67% •of projected increase in coal electricity generation in China, 2015–2030 (IEA, 2009b );

the biomass required is 95 Mt/yr dry biomass or 25% of prospective •crop residue supplies available for energy in China; 17

CO • 2 would be stored in deep geological formations at a rate of 2.57 Gt/yr.

This coproduction approach also would offer significant advantages rela-tive to provision of the same energy products via use of CTG-RC-CCS (a

coal-only design that maximizes gasoline output) plants plus CIGCC-CCS plants to provide the electricity needed in excess of what can be provided by the CTG-RC-CCS plants. Relative to the case with production in separ-ate facilities, the coproduction with coal/biomass coprocessing approach would involve comparable total investment, total primary input, and CO 2 storage requirements, but would generate 15% less GHG emissions. Moreover, when evaluating the coproduction system as an electricity generator, the levelized cost of electricity at crude oil and GHG emissions prices of US$90/bbl and US$65/tCO 2 -eq, respectively, would be only 14% as large as for a 2028 MW e CIGCC-CCS plant having the same primary energy input as the average coproduction unit that provides 768 MW e of electricity. The reasons for the outstanding economic performance of coproduction plants evaluated as electricity generators compared to stand-alone power plants are discussed in Section 12.6.3 .

Africa Why Africa? The region of Africa is a good candidate for deployment of BTG-RC-CCS technology in the 2030+ time frame. There are many reasons:

Much of Africa is biomass-rich but coal-poor (except for Botswana •and South Africa).

Much of Africa is economically poor and in need of industrial develop- •ment such as that which BTG-RC-CCS technology could help provide.

Africa has a huge population in need of clean cooking fuels, with •some 710 million people (Hutton et al., 2006 ) dependent on solid fuels for cooking. 19

Much of Africa must spend precious export earnings on fuels for trans- •portation as well as on LPG for cooking and thus stands to benefit economically from having a domestic BTG-RC-CCS synfuels industry.

Preliminary indications are that there might be significant CO • 2 stor-age opportunities in Africa (see Chapter 13 ).

Although at low GHG emissions prices it would make more eco- •nomic sense for biomass-rich/coal-poor countries to import coal and make gasoline by coprocessing coal and biomass, biomass to gasoline plants would become more cost competitive at high GHG emissions prices. 20 So, if there were a reasonable expectation of such high GHG emissions prices in the future, perhaps before 2050, such

18 Following the fi ndings of Hutton et al., ( 2006 ) it is assumed that the average per capita LPG requirement for China is 29.3 kg/yr (43 Watts).

19 In 2006 biomass used for cooking in the developing world (assumed to be total bio-mass use for energy, minus biomass used for power generation, minus industrial use of biomass, and minus biomass used to make transport fuels) was 229 Mtoe (9.6 EJ) in Africa, 224 Mtoe (9.4 EJ) in China, 131 Mtoe (5.5 EJ) in India, 142 Mtoe (6.0 EJ) in other non-OECD Asia, and 32 Mtoe (1.3 EJ) in Latin America (IEA, 2008b ). Thus Africa accounted for about 30% of global biomass use for cooking in 2006.

20 If the competition were between CBTG-PB-CCS and BTG-RC-CCS plants each con-suming 0.5 million dry tonnes of biomass annually, the BTG-RC-CCS option would provide gasoline at a lower levelized cost of fuel when the GHG emissions price is greater than US$108/tCO 2 -eq.


955

countries might be reluctant to make such coal-related infrastructure investments.

The thought experiment : A thought experiment is presented that envi-sions widespread deployment of BTG-RC-CCS technology in Africa in the 2030+ time frame.

Assumptions: The following conditions are assumed:

Before 2030 all the needed technological components are estab- •lished in the market somewhere in the world via earlier widespread deployment of CTG-PB-CCS and CBTG1-PB-CCS technologies (e.g., as described in the previous China thought experiment).

The GHG emissions price is high enough (greater than US$62/tCO • 2 -eq) that BTG-RC-CCS is able to sell gasoline that is competitive with gasoline derived from US$90/bbl of crude oil (see Figure 12.30 ).

There are concerted multilateral activities prior to 2030 aimed at: (i) •identifying geological CO 2 storage opportunities in Africa’s biomass-rich regions; (ii) identifying prospective biomass supplies that can be provided on a sustainable basis (avoiding supplies that involve defor-estation, destruction of soil carbon stores, and competition with food production); (iii) building in currently economically poor, biomass-rich regions the physical infrastructures and human capacity needed to support rapid development of a BTG-RC-CCS industry.

BTG-RC-CCS plants are deployed at modest scales to keep biomass •supply logistics and CO 2 infrastructure challenges from being too daunting—producing gasoline at a scale ~2300 bbl/day, process-ing only 0.5 Mt/yr of dry biomass, and storing underground only 0.5 Mt/yr of CO 2 , see Table 12.21 . To get a sense of the scale of the activities, consider that Campbell et al. ( 2008 ) have estimated for tropical regions that yields for growing mixed prairie grasses on abandoned cropland in tropical regions are 7–20 dry t/yr-hectare. For these yields the amount of land required to serve a single bio-fuels plant is 250–714 km 2 . The average biomass transport distance is 30–50 km if the biomass is available on 20% of the land around the plant and 40–70 km if the biomass is available on only 10% of the land.

For the thought experiment it is assumed that the amount of bio- •mass available for prospective BTG-RC-CCS plants is the same as the actual estimated amount of biomass that was used for cook-ing in 2006 (229 Mtoe/yr = 9.59 EJ/yr). 19 If this much biomass were grown as an energy crop at a yield of 7–20 dry t/hectare-yr, some 27–78 million hectares would be required for all of Africa. To put this into perspective, Cai et al. ( 2009 ) estimates that worldwide the amount of land available for growing biomass for energy on both abandoned and/or degraded cropland and grassland, savanna, and shrubland with marginal productivity suitable for use with low-input

high diversity prairie grasses as energy crops is 1343 million ha of which one third to one half (450–670 million hectares) is in Africa. 21

Making cooking with LPG affordable : The analysis below explores pros-pects for earning income that current users of biomass for cooking might pursue. They could sell their biomass to “biomass-supply-logistics” agents, who would in turn make the biomass available to operators of BTG-RC-CCS plants. And they could generate thereby enough revenue to cover both purchases of LPG for cooking and the annualized cost of purchasing an LPG stove and storage canisters.

Compare the energy requirements for cooking with these fuels. The cur-rent rate of use of biomass for cooking by 710 million people in Africa (229 Mtoe/yr, 9.6 EJ/yr), 19 corresponds to a wood consumption rate of 0.7 dry tonnes per capita/yr = 428 Watts/capita. According to Hutton et al. ( 2006 ) the average per capita consumption rate of LPG for cooking in Africa as a substitute for wood would be 14.4 kg/yr or 21 Watts. Both of these cooking rates are consistent with historical rates for cooking with wood and fluid fuels ( Figure 12.28 ).

Energy requirements for cooking via LPG are only ~5% of the energy requirements for cooking via the direct burning of biomass. This makes LPG prospectively affordable even for very poor households. The follow-ing illustrative calculation suggests how LPG might be made affordable: Suppose that the crude oil and GHG emissions prices are US$90/bbl and US$70/tCO 2 -eq, respectively, so that synthetic gasoline produced with carbon capture and storage would be cost-competitive with gasoline from crude oil ( Figure 12.30 ). At these crude oil and GHG emissions prices, the estimated average retail LPG price would be US$1.39/kg in rural Africa. 22 Thus the total average cost of LPG for a family of 4.4 (the average household size in Africa) would be:

4 4

3814 3

$ .1×⎛⎝⎜⎛⎛⎝⎝

⎞⎠⎟⎞⎞⎠⎠

× =USkg

kgcapitayr

US$87yr

(3)

The total cost of cooking also includes capital expenses for the stove and storage canisters, which are estimated to be about US$50 (IEA, 2006 ) or an annualized cost of US$8/yr, 23 , 24 so that the total annualized

21 Of the global total Cai et al. ( 2009 ) estimate that 256–463 million hectares is aban-doned and/or degraded cropland. For comparison, Campbell et al. ( 2008 ) estimate that globally the amount of land available on abandoned cropland is 385–472 mil-lion hectares.

22 Based on a wholesale LPG price of $1.07/kg for $90/bbl + a $0.31/kg markup to retail for rural Africa, as estimated in Hutton et al. ( 2006 ).

23 Assuming a 10% discount rate and a 10-year system life, the capital recovery factor is 16.3%/yr for the capital equipment.

24 Some sort of microfi nancing program may be needed to overcome the expenditure “lumpiness” hurdle of the stove/canisters investment, but otherwise the required investment would not appear to be a show-stopper for poor households.


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cost is US$95/yr per average African household. The price P W (in US$/t) at which a family would have to sell biomass currently used for cook-ing to a biomass-supply-logistics agent of a synfuel producer in order to be able to afford the LPG without an additional income stream is given by:

4 4 0 70.4 0×

⎛

⎝

⎜⎛⎛

⎜⎜⎜

⎜⎝⎝

⎜⎜

⎞

⎠

⎟⎞⎞

⎟⎟⎟

⎟⎠⎠

⎟⎟ × = ⇒ =tonnes

woodcapita

yrP

US$95yr

P U= S$31W W= ⇒PP peree tr onne (4)

This is a plausible selling price because it is only 30% of the assumed price of wood delivered to the conversion facility 25 − allowing a mar-gin of revenue to the biomass-supply-logistics agent that is plausibly enough to pay for profitably getting the biomass purchased from cook-ing fuel consumers to the synfuel producer. (Detailed biomass supply logistics analysis is needed to ascertain the validity of this very prelim-inary judgment.)

Implications of the thought experiment for Africa : The biomass now used for cooking in Africa could support the operation of 1023 BTG-RC-CCS plants like those described in Table 12.21 . If such a shift in biomass use were made, there would be Africa-wide implications:

a total investment requirement for BTG-RC-CCS plants of US$528 •billion;

enough LPG to meet the cooking fuel needs of 94% • 26 of the popula-tion currently cooking with biomass;

2.28 million bbl/day average gasoline output, equivalent to 90% of •Africa’s transportation fuel demand for 2030 as projected by the IEA (IEA, 2010 ) or 11% of world gasoline output of refineries in 2007 , some 21.3 million bbl/day (47 EJ/yr) (US EIA, 2009b );

88 million MWh/yr of electricity, equivalent to 7% of Africa’s electri- •city generation in 2030 as projected by the IEA; and

annual storage in geological formations of 562 MtCO • 2 /yr.

Toward a business plan for BTG-RC-CCS technology deployment in Africa : This thought experiment suggests that widespread deployment of BTG-RC-CCS technology in Africa might not only go a long way

towards meeting Africa’s transportation fuel needs but also might help to catalyze widespread use of LPG for cooking, even among very poor households.

But much new thinking is needed about business strategies and public policies required to convert this thought experiment into a plausible energy projection for Africa. A list of proposed public policies for both the China thought experiment and the Africa thought experiment is pre-sented in Section 12.5.3.2 .

Although articulating appropriate business plans is beyond the scope of the current analysis, we conclude the economic analysis with a sug-gestion for one possible element of such business plans: involvement of industrial firms that produce and/or use crude oil-derived transportation fuel as investors in BTG-RC-CCS systems.

The reason for this suggestion is that such firms may be interested in procuring credits for the strong negative GHG emissions characteriz-ing BTG-RC-CCS systems to offset emissions from the crude oil-derived products they produce or consume. The production of each barrel of gasoline by a BTG-RC-CCS plant provides enough negative GHG emis-sions to offset the emissions of 1.37 barrels of crude oil-derived gas-oline. 27 Assuming that crude oil and GHG emissions prices are US$90/bbl and US$70/t, respectively, the annual cost of purchasing credits from a single BTG-RC-CCS plant would be US$34 million. The present worth of purchasing such credits over the life of the plant would be US$357 million, 28 which is about three fourth of the investment cost (TPC) for a BTG-RC-CCS plant ( Table 12.21 ).

The industrial firms that are producers and/or users of crude oil-derived transportation fuel could either try to buy emissions credits from BTG-RC-CCS plant owners in an emissions trading market or they could instead invest in BTG-RC-CCS plants. In the former case, they would risk not being able get the full amount of credits they are seeking to obtain, while in the latter case they would have guaranteed access to these credits.

25 For all the systems presented in Figure 12.30 and involving biomass it is assumed that the delivered price of biomass at the conversion plant is $5.0GJ (HHV), which corresponds to a wood price of $103/dry tonne.

26 The cooking fuel production could be increased to 100% of the current cooking fuel needs by reducing the gasoline output of the BTG-RC-CCS plants in favor of pro-ducing some DME as a coproduct and blending this with LPG for use as a cooking fuel. So doing would be straightforward because the fi rst step in the production of gasoline from methanol (CH 3 OH) is methanol dehydration, which produces DME (CH 3 OCH 3 ) and water. See additional discussion of DME in Section 12.5.1 .

27 Alternatively, offsets might be sought from plants that make electricity via gasifi -cation of biomass with CCS, in which case a much larger fraction of the C in the biomass can be stored underground. If the negative emissions from power plants are used to offset emissions from crude oil-derived gasoline, a comparable amount of “effective” zero GHG emitting liquid fuels would be provided via the biomass to power with CO 2 capture and storage route as via the BTG-RC-CCS route (1.04 and 0.94 GJ of zero net GHG-emitting gasoline is provided per GJ of dry biomass input in the BTG-RC-CCS and power-only cases, respectively). In the power-only case, the gasoline provided is 100% crude oil-derived gasoline offsets; in the BTG-RC-CCS case, 42% of the gasoline is actually produced and 58% is in the form of crude oil-derived offsets. Thus if a biomass-rich country seeks to reduce oil imports as well as mitigate climate change, it is likely to choose the synfuel option over the power option. Another consideration that might tip the balance in favor of the synfuel option is that CO 2 storage capacity is a non-renewable resource, and the power option stores 1.6 times as much CO 2 per tonne of biomass as the synfuel option.

28 Assuming a 7% discount rate and a 20-year economic life of a BTG-RC-CCS plant.


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12.5.3.2 Public Policy Issues

Despite the huge public benefits and seemingly attractive economics indicated by the China and Africa thought experiments, converting these thought experiments into projects will require new public pol-icy initiatives. There would be many hurdles to overcome, including issues related to the viability of CO 2 storage at gigascale, CO 2 stor-age potential, sustainable biomass production potential, commer-cialization of large biomass gasifiers, new industrial collaborations, the rural lighting challenge, and physical infrastructure and human capacity for a BTG-RC-CCS industry. These public policy issues are outlined here.

Viability of CO 2 storage at gigascale : There is widespread belief in the scientific community that CCS is a viable carbon mitigation option at scales storing billions of tonnes of CO 2 annually worldwide (IPCC, 2005 and Chapter 13 ). Demonstration projects are needed, however, to prove and gain a high degree of confidence in CCS viability and also to provide a solid scientific and engineering basis for widespread deployment of CCS technologies post-2020. Commercial-scale integrated CCS demon-stration projects worldwide are needed during the coming decade, with emphasis on CO 2 storage in deep saline formations, which account for most of the geological storage opportunity. Such projects are needed for several reasons. They could address scientific questions that can only be answered in projects that inject and store CO 2 at rates comparable to those for commercial projects. They could demonstrate to the satis-faction of a wide range of stakeholder groups that CCS is a viable major option to be included in the portfolio of carbon mitigation options. And they could provide the experience base needed for formulating practic-able regulations governing CO 2 storage.

An international political framework for early CCS action has already been established. In July 2008, an agreement was reached by the G8 countries at the G8 Summit in Japan that 20 large-scale fully inte-grated CCS demonstration projects worldwide would be deployed by the middle of the next decade, with the aim of establishing the basis for broad commercial deployment of CCS technologies after 2020. In July 2009 , the leaders of the G8 countries re-iterated their call for the projects, and in February 2010 US President Obama issued a Presidential Memorandum calling for five to ten commercial scale CCS demonstration projects to be up and running in the United States by 2016.

Much if not all of the incremental cost of CCS for the 20 projects called for by the G8 will probably have to be paid for by governments (indi-vidually or collectively) because of the likelihood that carbon prices will be lower initially than what will be needed to make pursuit of CCS a profitable activity for private companies.

If governments will have to pay for the incremental CCS cost, they will want to pursue projects in which they can maximize the learning about the gigascale prospects of CCS per dollar spent.

An important consideration is that coproduction systems based on coal or coal + biomass generate, as a natural part of the process of their manufacture, relatively pure streams of CO 2 for which the incremen-tal cost of CO 2 capture is low. Accordingly, coproduction facilities (such as the CTG-PB-CCS and CBTG1-PB-CCS described in Table 12.21 ) built in coal-rich countries should be considered seriously as candidates for some of the needed CCS early action projects and supported financially jointly by the governments of several coal-intensive energy economies.

CO 2 storage potential : CO 2 storage prospects are not well known in countries where clean cooking fuels are sorely needed and where attractive economics for providing these fuels to poor households can plausibly be realized in conjunction with the building of synfuel plants with CCS. “Bottom-up” assessments of storage prospects, including the construction of supply curves (storage capacity in tonnes vs cost in US$/t), are needed on a reservoir-by-reservoir basis. These assess-ments should be carried out in each of the major regions requiring clean cooking fuels − with financial support from the international community.

Sustainable biomass production potential : Assessments should be car-ried out in biomass-rich regions to determine the prospects for biomass production for energy. Such production should be on a sustainable basis in which conflicts with food production, adverse indirect land-use impacts, and biodiversity conflicts are minimized. Emphasis should be on agricultural residues, forest residues (including mill residues, logging residues, diseased tree removals, fuel treatment thinnings, and prod-uctivity enhancement thinnings), and the growing of dedicated energy crops on abandoned croplands and other degraded lands. The growing of bioenergy crops on marginal lands should be done in ways that enhance the wellbeing of poor indigenous populations currently use such lands for their livelihoods. One way of expanding biomass production on mar-ginal lands without forcing off the land local populations would be to encourage the local populations to grow biomass for energy by creating corporate smallholder partnerships that establish agreements for indus-tries to purchase biomass from smallholders. Outgrower schemes such as these have been common for some time in agriculture; smallholders are now playing an increasingly important role in the establishment and management of planted forests (Cushion et al., 2010 ).

These assessments should be carried out in each of the major regions requiring clean cooking fuels − with financial support from the inter-national community.

Commercialization of large biomass gasifiers : Successful demonstration projects have been carried out for biomass gasifiers at small scales (pro-cessing tens of MW of biomass). But there are no commercial biomass gasifiers capable of processing 300–600 MW of biomass − the scales for the conversion systems described here. Policies are needed to encourage commercialization of biomass gasifiers suitable for coupling to synthetic fuel production units at these scales. Such commercialization efforts should be carried out in parallel with early deployment of CBTG1-PB-CCS


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systems (designed for ~10% biomass or less) that could involve instead co-gasification of biomass and coal in suitable coal gasifiers.

New industrial collaborations : New public policies are needed to facili-tate industrial collaborations between companies producing trans-portation fuels, electricity, and clean cooking fuels and to encourage coprocessing of coal and biomass in regions having significant supplies of both (e.g., United States and China). It would be desirable to identify policy instruments that specify performance rather than technology and maximize use of market forces in meeting performance goals. Promising approaches along these lines include mandating a Low Carbon Fuel Standard (as in California); a low carbon standard for coal electricity, perhaps modeled after Renewable Portfolio Standards or green certifi-cate markets; and a Universal Clean Cooking Fuel Standard in regions requiring major infusions of clean cooking fuels, perhaps modeled after the “obligation to serve” mandates of the rural electrification programs introduced in the United States in the 1930s. The latter could plausibly facilitate the formation of strategic industrial alliances that would be capable of guaranteeing universal access to clean cooking fuels without major subsidy.

Rural lighting challenge : Policies aimed at inducing a shift from biomass to clean cooking fuels should be complemented by policies to promote universal access to modern lighting technologies (see also Chapter 23 ).

Physical infrastructure and human capacity for a BTG-RC-CCS industry : Official development assistance (ODA) should be expanded for eco-nomically poor but biomass-rich and coal-poor regions. The increment should be directed to developing the physical infrastructures and human capacities needed to build and manage large BTG-RC-CCS industries. This additional ODA should aim for established infrastructures and cap-acities before GHG emission prices are high enough to launch BTG-RC-CCS technologies in the market.

12.6 Coproduction of Liquid Fuels and Electricity from Non-petroleum Feedstocks

Coproduction can enhance cost-competitiveness. The discussion of gas-ification-based synfuels in Section 12.4.3 was focused on recycle (RC) systems designed to maximize liquid fuel output. In RC systems, syngas unconverted in a single pass through the synthesis reactor is recycled to the reactor to maximize synfuel yield. A major study of alternative system configurations for making FTL from coal, from biomass, and from coal + biomass (Liu et al., 2011a ) found that FTL can often be produced more cost-effectively in so-called “once-through” (OT) systems, in which syngas unconverted in a single pass is burned to make coproduct electri-city in a gas turbine/steam turbine combined cycle power plant (See also Larson et al., 2010 ). OT configurations are worthwhile exploring from a synfuels production perspective for the slurry-phase synthesis reactors investigated by Liu et al. ( 2011a ) because these reactors can yield high

one-pass conversion of CO+H 2 to liquids − much higher than is feasible with gas-phase reactors. A major study of alternative system configura-tions for making gasoline via the methanol-to-gasoline process from coal, from biomass, and from coal + biomass (Liu et al., forthcoming ) also found that gasoline can often be produced more cost-effectively via systems that produce electricity as a major coproduct.

Here the merits of coproduction for both FTL and MTG systems are dis-cussed for the six systems described in Table 12.22 that involve coal (both –V and –CCS configurations) and coal + biomass (only –CCS con-figurations). Since detailed descriptions of RC variants of FTL and MTG systems were already made in Section 12.4.3 , here only the major differ-ences introduced by the coproduction designs are discussed.

Figure 12.31 shows several OT configurations for coal and coal/biomass FTL systems. When iron-based synthesis catalysts are used (as in the analysis in Liu et al., 2011a ), CO 2 removal from synthesis gas in –CCS configurations is required downstream as well as upstream of synthe-sis because of the water-gas-shift activity of iron-based catalysts, and downstream CO 2 removal accounts for more than half of the total CO 2 removed. Also, a gas turbine/steam turbine combined cycle rather than a steam turbine is used to generate electricity on the power island.

The MTG designs that coproduce electricity and gasoline use a bypass of some of the syngas around the methanol synthesis reactor to directly feed a gas turbine/steam turbine combined cycle power plant in so-called partial bypass (PB) configurations ( Figure 12.32 ). 29 An additional water gas shift reactor is introduced to convert the bypass syngas to mainly CO 2 and H 2 , from which the CO 2 is captured for storage, and H 2 is the main constituent of the fuel gas delivered to the combined cycle power plant.

12.6.1 Performance Estimates

Greenhouse gas emissions are the focus of the discussion of perform-ance estimates here. To facilitate comparisons, the coal-only plants ( Figure 12.31 , Table 12.22 ) have the same levels of coal inputs as the corresponding RC plants described in Table 12.15 that provided 50,000 bbl/day of crude oil products displaced for both FTL and MTG. As shown in Table 12.22 , the OT and PB system configurations produce less liquid fuel and much more electricity from this coal than the corresponding RC systems. As in the RC cases, an important metric for comparing emis-sions for different system configurations is the GHGI: the ratio of the fuel cycle wide emissions of greenhouse gases from these systems are compared to emissions from a reference system.

29 A partial-bypass, rather than a “once through” (OT), process design is utilized for the MTG systems here because the assumed methanol synthesis reactor is a gas-phase design, for which the per-pass conversion of syngas is small, making it ill-suited for use in an OT pro-cess confi guration. A liquid-phase methanol synthesis reactor would have much higher single-pass conversion and as a result might be better-suited for an OT application.


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Table 12.22 | Performance estimates for converting coal and coal + biomass to electricity + FTL or MTG.

Process configuration >>>

CTL-OT-V CTL-OT-CCS CTG-PB-V CTG-PB-CCS CBTL-OT-CCS CBTG-PB-CCS

Coal input, as received metric t/day

24,087 24,087 20,869 20,869 3220 5260

Coal input, MW HHV 7559 7559 6549 6549 1011 1651

Biomass input, as received metric t/day

0 0 0 0 3,581 3,581

Biomass input, MW HHV 0 0 0 0 661 661

Production of all liquids, MW LHV

2256 2256 2100 2100 508 743

Production of LPG, MW LHV - - 202 202 - 68

Production, bbl/day COPD a , excl. LPG

35,706 35,706 32,579 32,579 8,036 11,582

Gross electricity production, MW

1661 1653 1417 1369 384 521

On-site electricity consumption, MW

401 595 459 609 127 229

Net electricity exports to grid, MW

1260 1058 959 760 257 292

Energy ratios

Liquids out/energy in (HHVs) 32.1% 32.1% 34.4% 34.4% 32.5% 34.5%

Net electricity/energy in (HHV) 16.7% 14.0% 14.6% 11.6% 15.4% 12.6%

(Liquids+electricity)/energy in (HHVs)

48.8% 46.1% 49.1% 46.0% 48.1% 47.2%

Carbon accounting

C input as feedstock, kgC/second

178 178 154 154 40 55

C stored as CO 2 , % of feedstock C

0.0% 52.2% 0.0% 63.7% 54.0% 64.9%


4.0% 4.0% 4.0% 4.0% 3.6% 3.7%

C vented to atm., % of feedstock C

71.6% 19.5% 70.5% 6.8% 18.2% 6.3%

C in liquid fuels, % of feedstock C

24.4% 24.4% 25.5% 25.5% 24.2% 25.1%

C stored, 10 6 tCO 2 /yr (at 90% cap factor)

0 9.6 0 10.2 2.3 3.7

Full fuel cycle GHG emissions (incl. from feedstock supply and conversion, fuels distribution and use)

kgCO 2 -eq/GJ liquid fuel LHV 289.6 139.1 298.3 108.9 19.4 19.7

tCO 2 -eq/hr 2352 1129 2038 744 35 48

Reference system emissions, tCO 2 -eq/hr

1790 1623 1483 1318 381 538

GHG emissions index – GHGI b 1.31 0.70 1.37 0.56 0.093 0.089

a COPD = crude oil products displaced. b GHGI, the greenhouse gas emissions index, is the system wide life cycle GHG emissions for production and consumption of the energy products relative to emissions from a refer-

ence system producing the same amount of liquid fuels and electricity. For details, see Table 12.15 , note (c).


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Figure 12.31 | CTL-OT-V system (including only yellow-shaded components) that provides F-T liquids + electricity from coal via gasifi cation while venting the captured CO 2 coproduct. Upstream of the synthesis reactor CO 2 accounting for 25% of the C in the coal is captured along with H 2 S using Rectisol. The H 2 S is converted to elemental sulfur in a Claus plant and the CO 2 is vented.

With the addition of the blue-shaded components, the system (CTL-OT-CCS) includes capture of CO 2 both upstream of the synthesis reactor (accounting for 25% of C in the coal) and downstream of it (accounting for 27% of C in the coal). The CO 2 is compressed to 150 bar and delivered to a pipeline for transport to a geological storage site.

With the further addition of the green-shaded components, the system (CBTL-OT-CCS) co-processes biomass with coal.

And fi nally, the further addition of the red components creates a design (CBTL-OTA-CCS) that includes autothermal reforming (ATR) of the C 1 -C 4 components in the fuel stream to the power island, followed by water gas shifting. The autothermal reforming (ATR) plus WGS creates more CO 2 for capture downstream of synthesis than is the case with the CBTL-OT-CCS system.

Both the CBTL-OT-CCS and CBTL-OTA-CCS systems have been designed with enough biomass to realize GHGI < 0.10. CBTL-OT-CCS, storing as CO 2 54% of the feedstock C, requires coprocessing 40% biomass, whereas CBTL-OTA-CCS, storing as CO 2 65% of the feedstock C, requires coprocessing only 29% biomass to realize essentially the same GHGI value.

Gr in di ng & Sl u rry Pr ep .

Gasi fi cat io n & Qu en ch

Syngas Sc ru bb er

Wat er Gas Shi ft

Ac id Gas Re mo va l

Met ha no l Synt he si s

Met ha no l Recov er y

MT G reac to r

Refin in g

Refrig er at io n pl an t

Fl as h

Fl as h

R eg e ne ra ti on

Co al

Water Slag

Oxyg en pl an t

Air

Gas cooling

Me th an ol

CO 2

CO 2

H 2 S + CO 2 To Cl au s/ SCOT

150 bar CO 2 To pi pe lin e

Water

Pu rge gas

Cr ud e

Met hano l

Fi ni sh ed Gas ol in e

LPG

Fu el gas Recycl e Co mp r.

Recycled Sy n gas

s a t ur a t o r

Wa te r Ga s Sh if t

C O

2 r em ov a l

CO 2 En ri ch ed me th an ol

Me th an ol

Ste am GT CC Power Is la nd

N 2

Fl ue gas

Net exp or t elec tric it y

Oxyg en

Sy n gas Bypas s 0. 35

0. 65

Ch opp ing &

Lock h oppe r FB Ga si fie r &C yc lo ne

Ta r Crack in g Fi lte r

Biomas s

CO 2 Dry as h

Gas coo lin g

Compressure

Ox yge nS te am

Figure 12.32 | CTG-PB-CCS system (yellow-shaded components) that provides gasoline and LPG + electricity from coal. H 2 S is converted to elemental sulfur, and CO 2 is captured both upstream and downstream of synthesis (accounting for 64% of C in the coal), compressed to 150 bar, and delivered to a pipeline for transport to a geological storage site. With the addition of the green-shaded components, the system (CBTG-PB-CCS) produces gasoline and LPG + electricity from coal and biomass. CO 2 accounting for 65% of C in the feedstocks is captured and sent to geological storage.


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For the coal-only designs, the GHGI is 1.3–1.4 for the systems with venting of CO 2 , indicating that emissions would be considerably higher than for the reference system. Adding carbon capture and storage reduces emissions relative to the reference system by 30–40% (GHGI = 0.56–0.70).

The two coal + biomass systems described in Table 12.22 are each designed for a total biomass consumption of 1 Mt/yr dry biomass, together with an amount of coal that results in a GHGI of 0.1 or less, i.e., 10% of the emissions of the reference system or less. For the FTL systems, 40% of the input feedstock energy is biomass. It is 29% for the MTG system. Unlike systems that produce liquid fuels using only biomass as a feedstock, the energy content in the near-zero GHG liquid fuels produced from coal/biomass systems is comparable to or greater than the energy contained in the input biomass (see Figure 12.33 ). The reason is that a large percentage of the energy input for these coal/biomass coprocessing options is provided by coal, as shown in Figure 12.33 .

12.6.2 Cost estimates

When coproduction systems are evaluated from a fuels perspective, the LCOF is given by:

LCOF

levelized system costUS$

yrlevelized value of electri

=

− city coproduct ccUS$

yr

levelized fuel production rateGJ

yr

(5)

In Liu et al. ( 2011a ) and in Liu et al. ( forthcoming ) it is assumed that the electricity coproduct is valued at the US average grid generation price in 2007 (US$60/MWh) augmented by the value of the average grid GHG emission rate in that year (see Figure 12.10 ).

Figures 12.34 and 12.35 present LCOFs vs GHG emissions price for the coal only – OT and –PB systems, respectively, as well as the correspond-ing LCOFs for the RC alternatives.

Figure 12.34 | Comparison of CTL production costs (US 2007 $): OT vs RC options, both with CO 2 vented (–V) and with carbon capture and storage (–CCS). (See Table 12.6 , note (b) for fi nancial parameter assumptions. Also, electricity sales are assumed at the US average grid price plotted in Figure 12.10 .) Source: based on Liu et al., 2011a .

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

EtOH-V EtOH-CCS

BTG-RC-V

BTG-RC-CCS

BTL-RC-V BTL-RC-CCS

CBTL-OT-CCS

CBTL-OTA-CCS

CBTL-RC-CCS

CBTG-RC-CCS

CBTG-PB-CCS

stupni ygrene yramirP

)V

HL leuf duqil JG rep

VHL J

G(COALBIOMASS

kWh electricity per GJ of liquid fuel

5.0 1.5 30 19 41 30 141 116 23.7 4.4 109

GJ LPG per GJ of liquid fuel

0.0 0.0 0.095 0.095 0.095 0.092

Co-products

Figure 12.33 | Biomass (and coal) required to produce alternative fuels having low/zero fuel-cycle-wide GHG emissions. For this graph, all primary energy input is allocated to liquid fuels even though all systems also provide electricity. For details on the cellulosic ethanol options (EtOH-V and EtOH-CCS) see Box 12.3 . Source: based on Liu et al., 2011a .


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Figure 12.34 shows that the LCOF is 18% less for the CTL-OT-V case than for the CTL-RC-V case when the GHG emissions price is zero. This economic advantage of the OT option can be attributed in large part to the high marginal efficiency of power generation (Liu et al., 2011a ): for OT and RC plants having the same FTL outputs, the difference in electri-city outputs divided by the extra coal required for the OT case is 45% for the –V case and 39% for the –CCS case (HHV basis). In both instances these marginal efficiencies for power generation for OT options are much higher than for stand-alone power plants, e.g., 37.5% and 31.0% for CIGCC in –V and –CCS configurations, respectively ( Table 12.7 , PEI cases). For CTG systems, there are also gains in marginal efficiency, but the gains are not as pronounced as for CTL systems: the marginal effi-ciencies of incremental power generation are 38% for the –V case and 32% for the –CCS case.

For CTG systems ( Figure 12.35 ) the PB option offers no cost advantage relative to the RC case when CO 2 is vented, but for GHG emissions prices greater than US$40/t there is a significant production cost advantage for systems with CCS.

One reason why the economic benefit of coproduction is less for MTG systems than for FTL systems is that in the CTL case a shift from an RC to an OT configuration involves elimination of an energy- and capital-intensive autothermal reformer, whereas neither of the MTG recycle systems use autothermal reformers. Also, MTG systems need an extra water gas shift reactor to decarbonize the syngas stream going to the power plant, which is not needed for FTL systems.

OT systems for FTL and PB systems for MTG also offer less costly approaches to decarbonizing power than stand-alone power systems. To see this consider the cost of GHG emissions avoided (US$/tCO 2 -eq),

which is the GHG emissions price at which costs are equal for the –V and –CCS system configurations, i.e., the minimum GHG emissions price needed to induce CCS by market forces. This minimum GHG emissions price for both FTL and MTG systems is ~US$20/tCO 2 -eq ( Figures 12.34 and 12.35 ) compared to US$45/t or more for stand-alone power systems ( Figure 12.10 ). The reason for this large difference is that for synfuels pro-duction systems a substantial fraction of the carbon in the feedstock has to be removed from the shifted syngas upstream of synthesis as a natural part of the part of the process of making synthetic fuels. Moreover, in the FTL cases removal of the extra CO 2 downstream of synthesis is not very costly because no extra water gas shift reactors are required.

Figure 12.36 shows the LCOFs for all six OT and PB systems considered as a function of the GHG emissions price, based on the performance information presented in Table 12.22 and the additional economic infor-mation presented in Table 12.23 . An important feature of the curves presented in Figure 12.36 , is the rapid rate of decline in LCOF with GHG emissions price for both the CBTL-OT-CCS system and the CBTG-PB-CCS system − in stark contrast to the flat LCOF curves for the cor-responding RC systems presented in Section 12.4.3 . This rapid rate of cost reduction reflects the rising value of decarbonized electricity with GHG emissions price ( Figure 12.10 ). As a result of this sharp decline the LCOFs at US$100/tCO 2 -eq are US$15.6/GJ LHV (US$1.9/gallon of gasoline equivalent) for FTL via CBTL-OT-CCS (73% of the LCOF for FTL via CBTL-RC-CCS) and US$16.6/GJ LHV (US$2.0/gallon of gasoline equivalent) for gasoline via CBTG-PB-CCS (80% of the LCOF for gasoline via CBTG-RC-CCS). In both instances the liquid fuels are characterized by near-zero net GHG emissions, and large quantities of decarbonized coproduct power are provided.

Figure 12.35 | Comparison of CTG production costs (US 2007 $): PB vs RC options, both with CO 2 vented (–V) and with carbon capture and storage (–CCS). Same fi nancial parameter and electricity price assumptions as Figure 12.34 . Source: based on Liu et al., forthcoming . Figure 12.36 | Liquid fuel production costs (US 2007 $) for alternative FTL-OT and

MTG-PB options, involving coal and coal + biomass as feedstocks. Same fi nancial parameter and electricity price assumptions as Figure 12.34 . Source: based on Liu et al., 2011a .


963

12.6.3 Coproduction Economics from the Electricity Production Perspective

The economics discussed in the prior section focused on estimat-ing the cost of making liquid fuels via coproduction systems given assumed prices for the electricity coproducts. Alternatively, electricity

production costs can be estimated based on assumed liquid fuel sell-ing prices. 30 This alternative approach for evaluating the economics of

Table 12.23 | Capital cost and production cost estimates (US 2007 $) for coal and coal + biomass to electricity + FTL or MTG.

CO 2 vented or captured >>> CTL-OT-V CTL-OT-CCS CTG-PB-V CTG-PB-CCS CBTL-OT-CCS CBTG-PB-CCS

Coal input rate, MW HHV 7559 7559 6549 6549 1011 1651

Biomass input rate, MW HHV 0 0 0 0 661 661

Liquids production rate, MW LHV 2256 2256 2100 2100 508 743

LPG production rate, MW LHV 0 0 202 202 0 68

bbl/day crude oil products displaced, excl. LPG

35,706 35,706 32,579 32,579 8036 11,582


Air separation unit (ASU) + O 2 & N 2 compressors

711 742 681 675 217 270

Biomass handling, gasifi cation & gas cleanup

0 0 0 0 335 353

Coal handling, gasifi cation & quench 1468 1468 1301 1301 263 402

All water gas shift, acid gas removal, Claus/SCOT

636 727 598 705 151 324

CO 2 compression 0 60 0 70 24 34

F-T synthesis & refi ning or Methanol synthesis

519 519 347 347 171 155

Naphtha upgrading or MTG synthesis & refi ning

71 71 359 359 29 190

Power island topping cycle 272 280 227 231 80 141

Heat recovery and steam cycle 713 708 597 622 155 219

Total plant cost (TPC), million US 2007 $ 4390 4574 4110 4310 1427 2086

Specifi c TPC, US 2007 $/bbl/day 122,958 128,093 126,154 132,293 177,526 180,110

Levelized liquid fuel cost (US 2007 $/GJ LHV ) at US$0/tCO 2 a

Capital charges 10.57 11.01 11.75 12.32 15.26 16.77

O&M charges 2.74 2.86 3.05 3.20 3.96 4.35

Coal (at US$2.04/GJ HHV ; US$55/t, as received)

6.82 6.82 7.02 7.02 4.05 4.98

Biomass (at US$5/GJ HHV ; US$94/t, dry) 0.00 0.00 0.00 0.00 6.51 4.89

CO 2 transport and storage 0.00 0.73 0.00 0.86 1.22 1.22

Co-product electricity revenue (at US$60/MWh)

-9.31 -7.82 -8.42 -6.67 -8.44 -7.22

Co-product LPG revenue (for US$100/bbl crude oil)

- - -2.20 -2.20 - -2.09

Total liquid fuel cost, US 2007 $/GJ LHV 10.8 13.6 11.2 14.5 22.6 22.9

Total liquid fuel cost, US 2007 $/gallon gasoline eq (US$/gge)

1.3 1.6 1.3 1.7 2.7 2.8

Breakeven crude oil price, US 2007 $/bbl b 47 63 48 63 112 102

Cost of CO 2 emissions avoided, US 2007 $/tCO 2 - 21 - 20 24 21

a See note (b) of Table 12.6 for fi nancial parameter assumptions.

b See note (b) of Table 12.16 for discussion of the breakeven oil price calculation for MTG cases.

30 Here it is assumed that the synfuels are sold at the wholesale (refi nery-gate) prices for the crude oil products displaced, including the valuation of the fuel cycle-wide GHG emissions for these products. The relevant GHG emissions for the crude oil products displaced are given in Table 12.15 , note (c).


964

coproduction is of interest for three important reasons: (i) the incre-mental cost for carbon capture and storage is much less than for stand-alone power plants because, as already noted in Section 12.6.2 , much CO 2 must be removed from syngas prior to synthesis as a natural part of fuels manufacture, so that capture costs are low; (ii) the economics of power generation are attractive at current and prospective high oil prices, resulting in a huge credit against the cost of electricity gen-eration; and (iii) these systems can defend high capacity factors and force down capacity factors of competing technologies in economic dispatch competition. Coproduction is considered here for systems making Fischer-Tropsch liquids. First, we consider coproduction in the context of an evaluation of alternative options for new coal-using power plants ( Section 12.6.3.1 ), with potential applications in China ( Section 12.6.3.2 ). Second, we consider coproduction as an option for repowering old coal power plant sites ( Section 12.6.3.3 ), with poten-tial applications in the United States ( Section 12.6.3.4 ).

12.6.3.1 XTL vs Stand-alone Power Options for New Plant Construction

Table 12.24 lists key system characteristics for four coproduction options and two conventional stand-alone power options − each of which is designed to have 550 MW e of electric generating capacity. The reference technology is a new supercritical coal power plant that vents CO 2 (sup PC-V), the least costly option for new stand-alone coal power plants in the absence of a carbon constraint (see Section 12.2.2 ). Also listed is a coal integrated gasification combined cycle plant with carbon cap-ture and storage (CIGCC-CCS), currently the least costly CCS option for new stand-alone bituminous coal power plants ( Section 12.2.3 ). The CTL-OT options are identical to those considered in the previous two sub-sections except that the scales have been adjusted to 550 MW e of electric capacity. 31 Two options are considered that involve coprocess-ing just enough biomass to reduce the system GHGI to 0.5. Biomass

accounts for 12% of energy for one of these options, CBTL1-OT-CCS, which involves capturing only the naturally concentrated streams of CO 2 in the syngas 32 (accounting for 53% of carbon in the feedstock). Biomass accounts for 5% of energy input for the other option, CBTL1-OTA-CCS, which involves more aggressive CO 2 capture 33 (accounting for 64% of carbon in the feedstock). Thus the same GHG emissions mitiga-tion level is realized in one case by using more biomass and in the other by capturing more CO 2 .

For each of these options, curves for the levelized cost of electricity (LCOE) vs GHG emissions price is shown in Figure 12.37 for a levelized crude oil price of US$90/bbl, for US economic conditions. This is the oil price for the period 2020–2030 as projected by the IEA for a future in which the global community is then on a course aimed at stabilizing the atmospheric GHG concentration at 450 ppmv (IEA, 2009b ).

Several notable observations can be made about the curves in Figure 12.37 :

A GHG emissions price of only ~US$10/t is needed to induce a tran- •sition from CTL-OT-V to CTL-OT-CCS. In contrast a GHG emissions price of more than US$50/t is needed to induce a transition in stand-alone power generation from sup PC-V to CIGCC-CCS.

The LCOE curves for CBTL1-OT-CCS and CBTL1-OTA-CCS lie nearly •atop each other, meaning the extra capital cost for the more aggres-sive capture option is largely compensated by the lower fuel cost. 34

31 In adjusting plant scales it is assumed that system conversion effi ciencies do not change, but capital cost scale economy effects are taken into account.

Table 12.24 | Alternative systems with 550 MW e of electric power capacity.

TechnologyPrimary energy

input, MW (HHV)

Biomass input, kt/y

(%, HHV basis)

FTL output, barrels /day

(kt/year)

CO 2 stored, Mt/yr (% of feedstock C

stored)

TPC, million US 2007 $

GHGI a

Sup PC-V 1410 0 0 0 894 1.00

CIGCC-CCS 1780 0 0 3.62 (88) 1460 0.15

CTL-OT-V 3300 0 15,600 (658) 0 2200 1.31

CTL-OT-CCS 3930 0 18,600 (783) 5.01 (52) 2570 0.70

CBTL1-OT-CCS 3810 710 (12) 18,100 (763) 4.96 (53) 2630 0.50

CBTL1-OTA-CCS 4820 370 (5) 22,800 (963) 7.58 (64) 3300 0.50

a GHGI = system wide life cycle GHG emissions for production and consumption of the energy products divided by emissions from a reference system producing the same amount of liquid fuels and electricity. Here the reference system consists of electricity from a stand-alone new supercritical pulverized coal power plant venting CO 2 and equivalent crude oil-derived liquid fuels. For details, see Table 12.15 , note (c).

32 Both upstream and downstream of synthesis.

33 In the CBTL1-OT-CCS case, C1 to C4 gases in syngas downstream of synthesis are burned in the gas turbine combustor, thereby generating CO 2 that is vented to the atmosphere on the power island. In the CBTL1-OTA-CCS case an autothermal reformer and a water-gas-shift reactor are inserted downstream of synthesis to con-vert most of these C1 to C4 gases to mainly CO 2 and H 2 (see Figure 12.31 ). The extra CO 2 thus created is captured and stored. In this case the gas burned to make electricity is mostly H 2 . For additional details regarding this “autothermal reforming” option for once-through (OT) systems, see Liu et al., 2011a .

34 The assumed (HHV) fuel prices are $2.04/GJ for coal and $5.0/GJ for biomass.


965

Although not shown in the figure, the LCOE for coproduction sys- •tems declines sharply with the crude oil price: for each US$10/bbl increase in the crude oil price the LCOE at a GHG emissions price of US$0/t is reduced by US$12/MWh for CTL-OT-V and by US$17/MWh for CBTL1-OTA-CCS.

The LCOE for CBTL1-OTA-CCS is lower than for CTL-OT-CCS when the •GHG emission price is US$57/tCO 2 -eq.

The LCOE values represented by these curves are for design capacity fac-tors of 85% for power only systems and 90% for coproduction systems. In a market economy, however, capacity factors are determined not by the design engineers but rather by economic dispatch competition. Once a power plant is built, its capital cost ( a sunk cost ) is not taken into account in the determination of the merit order dispatch on an electric grid. The dispatcher operating the grid determines, on the basis of com-petitive bids, the order in which plants are dispatched to meet electricity demand − with those plants being dispatched first that offer to sell electricity at the lowest price. It is worthwhile for a power generator to bid to sell electricity as long as the revenue it gets from power (in US$/MWh) is not less than its short run marginal cost of producing electricity (SRMC, which excludes sunk costs). This minimum acceptable selling price for the generator is called the minimum dispatch cost (MDC).

As power generators, the XTL-OT plants considered here were designed as “must-run” baseload units. Their MDC depends on the oil price: oil revenues reduce the revenue required from electricity. The MDC is very low for coproduction systems at sufficiently high oil prices. In the CBTL1-OTA-CCS case, with zero GHG emissions price the MDC is the same as for sup PC-V if the crude oil price is US$37/bbl, and the MDC falls to zero when the crude oil price is US$51/bbl. Thus coproduction will be able to defend high capacity factors in economic dispatch competition

and force down the capacity factors of competing technologies as their deployment on the electric grid increases.

12.6.3.2 Thought Experiment for China

Coproduction technologies with CCS can be effective in addressing simultaneously climate change and energy security challenges. To illus-trate these benefits of coproduction strategies, a thought experiment is constructed in which it is imagined that all new power generation in China over the period 2016–2030 is shifted from the business-as-usual path of sup PC-V to a CCS path − considering for CCS, in turn, the CIGCC-CCS, CTL-OT-CCS, and CBTL1-OTA-CCS options listed in Table 12.24 . Although none of these alternatives to sup PC-V have been built, all system components for these three options are either commercial or commercially ready, so it would be technically feasible to deploy each of these options commercially beginning later in this decade. 35 The aim of the thought experiment is to gain a better under-standing of the strategic implications of pursuing coproduction options for power generation.

There are several reasons for focusing on China for this power-sector ori-ented thought experiment that are similar to the rationale for the China clean cooking fuel thought experiment discussed in Section 12.5.3.1 :

China has powerful reasons for becoming a world leader in identify- •ing and pursuing low-cost approaches to decarbonizing coal energy conversion such as via deployment of coproduction systems with CCS, as suggested by Figure 12.37 . 36 China is the world’s largest consumer of coal, the most carbon-intensive fossil fuel, accounting for 48% of world coal consumption in 2010. And the expectation is that under business-as-usual conditions coal demand will continue to grow in China (IEA, 2009b ).

China has a strong incentive to explore alternatives to oil imports. It •has evolved from being a net oil exporter in the early 1990s to being the world’s second largest consumer of imported oil in 2010, with the expectation of continued rapid oil import growth.

China has more experience with coal gasification technology than •any other country. Essentially all of this experience is in China’s chemical process industry, which is largely based on coal because of the scarcity of China’s oil and gas resources. There are nearly 400 operating and planned coal-based chemical plants in China using

Figure 12.37 | Levelized cost of electricity (LCOE) for crude oil at $90/bbl for the electric power options described in Table 12.24 . (See Table 12.6 , note (b) for fi nancial parameter values assumed.) The IEA (2009b) projects that if the global community were to pursue a GHG emissions trajectory consistent with stabilizing the atmos-pheric GHG concentration at 450 ppmv the world oil price would be fl at at US$90/bbl, 2020–2030, considerably lower than its projection of the world oil price for its Reference Case (BAU) scenario.

35 The modeling reported above for the CBTL1-OTA-CCS option (coprocessing 5% biomass) is for a system with separate gasifi ers for coal and biomass. For systems deployed in this decade, it is more likely that a single suitable coal gasifi er that can cogasify modest quantities of biomass with coal would be deployed instead.

36 Of course the LCOEs shown in this fi gure are only suggestive for China, because they were estimated for the United States, not Chinese, economic conditions. Moreover, the LCOEs for fi rst of a kind plants would be higher than those shown even in the US case, because the indicated costs are for N th of a kind plants.


966

coal gasification (Zheng et al., 2010 ); most are ammonia plants but there are also methanol plants, other chemical plants, and a few syn-thetic fuels plants. Evolving from the manufacture of chemicals and synthetic fuels in such a relatively mature gasification-based indus-try to the coproduction of liquid transportation fuels and electricity represents a relatively modest step forward from a technological perspective.

China has one of the world’s fastest-growing economies, and rap- •idly growing economies are the most favorable theatres for techno-logical innovation.

The starting point for the thought experiment is the US Energy Information Administration’s Reference Scenario for China (US EIA, 2009a ), in which it is projected that between 2006 and 2030 coal power generation will almost triple, total national GHG emissions will almost double, and oil imports will increase 3.4 times from 42% to 75% of liquid fuel consumption ( Figure 12.38 ).

Implications of the thought experiment for carbon mitigation are indicated in Figure 12.39 , which shows that in 2030, China’s GHG emissions would be less than for the business-as-usual case by the amounts 1.3 GtCO 2 -eq/yr, 1.9 GtCO 2 -eq/yr, and 2.3 GtCO 2 -eq/yr for the CTL-OT-CCS, CIGCC-CCS, and CBTL1-OTA-CCS trajectories, respect-ively. That the CBTL1-OTA-CCS path leads to 20% more GHG emis-sions mitigation than the CIGCC-CCS path even though GHGI = 0.5 for CBTL1-OTA-CCS compared to 0.15 for CIGCC-CCS arises because the coproduction option reduces emissions for liquid fuels as well as for electricity.

Implications of the thought experiment for China’s oil imports are indi-cated in Figure 12.40 . For the business-as-usual and CIGCC-CCS trajec-tories, oil imports grow from 162 to 551 Mt/yr (3.3 to 11.2 million bbl/day) between 2006 and 2030 but are reduced by 2030 to + 33 and – 86 Mt/yr (+ 0.68 and – 1.74 million bbl/day) for the CTL-OT-CCS and CBTL1-OTA-CCS trajectories, respectively.

In 2030 the biomass required for the CBTL1-OTA-CCS trajectory would be 235 Mt/yr − some 62% of the crop residue supplies potentially avail-able for energy applications in China in 2010 (Li et al., 1998 ).

Figure 12.38 | Business-as-usual (BAU) projection by US Energy Information Administration of China’s energy future, 2006–2030. Source: US EIA, 2009a .

Figure 12.39 | GHG emissions for China: for the BAU scenario based on US EIA ( 2009a ) and for the three thought experiment variants discussed in the main text.

Figure 12.40 | Oil imports for China: for the BAU scenario based on US EIA ( 2009a ) and for the three thought experiment variants discussed in the main text.


967

The coproduction trajectories might well require a substantial increase in China’s coal imports. However, coal imports are likely to pose less of an energy security challenge than oil imports, and the reduced oil import bill is likely to more than compensate for the increased cost of coal imports. 37

Of course, the economics of coproduction relative to conventional power must be evaluated under China’s economic conditions, and the coal/biomass supply implications of the thought experiment must be well understood before one can have a high level of confidence that this would be a cost-effective and otherwise attractive energy strategy for China. But the thought experiment suggests that investigating these issues would be worthwhile.

12.6.3.3 XTL-OT Systems as Repowering Options for Existing Coal Power Plant Sites

Decarbonization will be needed not only for new coal power plants but also for existing power plant sites. In industrialized countries such as the United States, the focus will be on existing power plant sites because overall electricity demand growth is expected to be slow. In this sec-tion, five systems providing Fischer-Tropsch liquid transportation fuels as coproducts of electricity and three stand-alone power systems are considered as repowering decarbonization options for sites of exist-ing written-off pulverized coal plants that vent CO 2 (WO PC-V). The coproduction options include both coal-only systems and systems that coprocess coal and biomass. Each of these repowering options is com-pared to a CCS retrofit of the WO PC-V plant (PC-CCS retrofit), based on analyses in Williams et al. ( 2011 ) and Liu et al. ( 2011a ). Key sys-tem characteristics for these ten systems are presented in Table 12.25 . The alternative systems are compared with regard to GHG mitigation performance, CO 2 storage requirements, energy penalties for CCS, site water requirements, and economics. However, the emphasis is on GHG emissions mitigation performance and economics.

A narrow definition of repowering is scrapping an existing power plant but keeping the site and its infrastructure for use by a new facility. Not all sites can accommodate repowering. There has to be enough space to accommodate all equipment associated with repowering, there have to be suitable CO 2 storage opportunities, and (for cases in which biomass is coprocessed with coal) biomass supplies have to be available. However, the definition of repowering is broadened somewhat to include also the option of abandoning the site entirely and rebuilding at a greenfield site if the targeted site is unsuitable. The economics change only rela-tively modestly in a shift from building a new plant at an existing site to

building a new plant at a greenfield site. The economic benefits associ-ated with saving the infrastructure are not taken into account.

For each of the ten options in Table 12.25 the LCOE vs GHG emissions price is shown in Figure 12.41 for US economic conditions. For the options involving CCS, it is assumed that the cost of CO 2 transport and storage is US$15/t for all options − higher than would be typical for new plant construction. For coproduction systems, the LCOE is evaluated for a lev-elized crude oil price of US$90/bbl, the oil price for the period 2020–2030 as projected in World Energy Outlook 2009 (IEA, 2009b ) for a future in which the global community is then on a course aimed at stabilizing the atmospheric GHG concentration at 450 ppmv. 38 As in the case of the larger-scale coproduction systems discussed in Section 12.6.3.1 , LCOEs are very sensitive to the crude oil price. 39 To assess the risk from an oil price collapse, the breakeven crude oil price for the five coproduction repowering systems is shown as a function of GHG emissions price in Figure 12.42 . 40

Particular attention is given to the five options for which GHGI is less than 0.20, in light of the fact that political leaders of many industrialized countries are targeting emissions reductions of 80% or more for their countries by mid-century.

Three of the coproduction systems were evaluated earlier from a fuels production perspective, though in some cases at different plant scales: CTL-OT-V, CTL-OT-CCS, and CBTL-OT-CCS ( Figure 12.31 ). One of the coproduction systems not discussed earlier is CBTL-OTA-CCS (also depicted in Figure 12.31 ), which has a GHGI below 0.1, as does CBTL-OT-CCS (0.077 vs 0.083, see Table 12.25 ) but realizes the low emission rate via more aggressive CO 2 capture (65% vs 54% of the C in the feed-stock is captured) along with a lower biomass input percentage (29% vs 40%). The other new coproduction option considered is CBTL2-OT-CCS for which a GHGI = 0.5 is realized with about 9% biomass input. This option is included because systems involving such a modest percentage of biomass in the feed could be ready for deployment in commercial-scale demonstration projects in this decade.

37 The extra coal required for the CBTL1-OTA-CCS option amounts to 2.1 tonnes of coal equivalent (tce) per tce of Fischer-Tropsch liquid transportation fuels produced. The IEA projects for its Reference Scenario that the coal import price for OECD countries will be $100/t in 2020 and $110/t in 2030 (IEA, 2009b ). For China, the cost of oil imports avoided for $90/bbl of crude oil would be 1.7 times the increased cost of coal imports if coal imported into China were to cost $110/t.

38 For this evaluation it is assumed that: i) the synthetic liquid fuel coproducts are sold at the wholesale (refi nery-gate) prices of the crude oil-derived products displaced (7.90 and 8.51¢ per liter refi ning markups for diesel and gasoline, respectively), and ii) selling prices increase with GHG emissions price by an amount equal to the fuel-cycle-wide GHG emission rates for these crude oil-derived products times the emissions price.

39 At a GHG emissions price of $0/t, the LCOE increases by an amount ranging from $12/MWh (for CTL-OT-V) to $16/MWh (for CBTL-OTA-CCS) for each $10/bbl reduc-tion in the levelized crude oil price.

40 The breakeven crude oil price is a metric for evaluating the economics of coproduc-tion systems from a synfuel producer’s perspective. It is the crude oil price at which the levelized costs of manufacturing the synfuel coproducts equal the wholesale (refi nery-gate) prices of the crude oil products displaced. In this calculation it is assumed that the electricity coproduct is sold at the average selling price for US electricity generation in 2007 ($60/MWh) augmented by the value of the US average electric grid emission rate in 2007 (638 kgCO 2 -eq/MWh). Figure 12.10 shows this electricity price vs GHG emissions price.


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A CIGCC system is included as a repowering option because, among cur-rently available technologies, this option offers the lowest LCOE among stand-alone coal power systems in new construction applications (see Section 12.2.3 ). The NGCC is also given close attention in light of recent bullishness about US gas supplies (MIT, 2010 ).

Simbeck and Roekpooritat ( 2009 ) analyzed and estimated LCOEs for several CCS retrofit options based on near-term technologies and showed that a simple CCS retrofit (without plant modification) based on an amine post-combustion scrubber offers the lowest LCOE for a retrofit, although the alternatives would be less energy-intensive. The least-costly CCS retrofit option identified in Simbeck and Roekpooritat is adopted with some of the cost assumptions adjusted to enable self-consistent comparisons in the analytical framework of Williams et al. ( 2011 ) and Liu et al. ( 2011a ).

The findings of this analysis for various alternatives to a WO PC-V plant are as follows:

PC-CCS retrofit : The CCS retrofit option is widely thought to be the pre-ferred option if coal use is to persist under decarbonization. This option is by far the least disruptive of the status quo. Its main attraction is that it requires the least capital investment among decarbonization options that involve coal use (see Table 12.25 ). However, this option involves a huge 36% energy penalty for CCS mainly because of the large amount of heat required to regenerate the amine solvent after it has absorbed the CO 2 from flue gases in which its partial pressure is only 0.14 atmos-pheres. This high energy penalty gives rise to a large (~33%) increase in the water requirements for the site, which will often greatly limit the viability of this option. The high energy penalty also implies a high min-imum GHG emissions price ~US$70/tCO 2 -eq to induce via market forces a shift from WO PC-V to PC-CCS retrofit (see Figure 12.41 ). 41

41 The point at which the PC-CCS retrofi t and WO PC-V curves cross determines the minimum GHG emissions price needed to induce CCS via market forces.

Table 12.25 | CCS retrofi t and repowering options for sites of written-off PC-V plants.

Capacities d

Energy penalty for CCS e (%)

Site raw H 2 O use at full output, f liters/s

(% of WO PC-V) GHGI g

CO 2 stored, Mt/yr

(% of input C stored)

TPC h , million US 2007 $

Inputs Outputs

Fuel, MW, HHV

Biomass, Mt/yr (%,

HHV basis)

Electricity, MW e

FTL bbl/day (MW, LHV)

WO PC-V a 1613 0 543 0 – 310 (100) 1.00 0 0

PC-CCS retrofi t a 1613 0 398 0 36.4 413 (133) 0.19 3.48 (90) 426

Repowering options

CIGCC-CCS b 1613 0 500 0 21.1 294 (95) 0.13 3.29 (88) 1369

CTL-OT-V b 1613 0 269 7,619 (481) – 232 (75) 1.17 0 1235

CTL-OT-CCS b 1613 0 226 7,619 (481) 8.6 245 (79) 0.63 2.06 (52) 1280

CBTL2-OT-CCS b 1694 0.23 (8.8) 242 8,036 (508) 8.6 253 (82) 0.50 2.19 (53) 1348

CBTL-OT-CCS b 1671 1.0 (40) 257 8,036 (508) 8.5 237 (76) 0.083 2.26 (54) 1427

CBTL-OTA-CCS b 2272 1.0 (29) 287 10,861 (686) 17.1 271 (87) 0.077 3.71 (65) 1784

NGCC-V c 1102 0 560 0 – 113 (37) 0.42 0 321

NGCC-CCS c 1102 0 482 0 16.3 171 (55) 0.11 1.36 (90) 583

a System characteristics as developed in Simbeck and Roekpooritat, 2009 . b Source: Williams et al., 2011 and Liu et al., 2011a . c System characteristics as developed by Woods et al., 2007 . d Capacities for systems using coal were determined by the following algorithms: i) Coal input rates cannot exceed the coal input rate of the WO PC-V plant displaced; ii) biomass

input rates cannot exceed 1.0 Mt/year; iii) CBTL2-OT-CCS has the same FTL output capacity as CBTL-OT-CCS. e For power-only systems, penalty = 100 x ( η v / η c – 1), where η v and η c are HHV plant effi ciencies for –V and –CCS options, respectively. For XTL-OT-CCS options, penalty = 100 x

(extra coal energy required via CIGCC-CCS to make up for lost power in shifting from –V → –CCS)/(coal energy use by XTL-OT-V). f Raw water usage = consumption – water recycled; estimated by authors for gasifi cation energy systems; based on Woods et al., 2007 for combustion energy systems, as discussed

in the main text. g GHGI = greenhouse gas emissions index = system wide life cycle GHG emissions for production and consumption of the energy products relative to emissions from a reference

system producing the same amount of power and liquid fuels. In this instance the reference system consists of electricity from a WO PC-V power plant (for which the GHG emis-sion rate is 998.8 kgCO 2 -eq/MWh e ) and equivalent crude oil-derived liquid fuels (for which the GHG emission rate is 91.6 kgCO 2 -eq/GJ).

h This is the total plant cost (TPC), or “overnight capital cost” (which excludes interest during construction).


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Repowering via CIGCC-CCS : With pre-combustion capture, the energy penalty for CCS and water requirements are both reduced more than 40% relative to the PC-CCS retrofit (see Table 12.25 ). In part this is because the CO 2 is captured at high partial pressure from shifted syngas instead of from flue gases. But also the low water require-ment reflects the fact that only ~1/3 of the power output of the com-bined cycle power plant is from the steam turbine, which requires the

consumption of water for condenser cooling purposes (the gas turbine topping cycle does not), and cooling water dominates water require-ments in all cases. These technical advantages do not imply a lower LCOE for the CIGCC-CCS repowering option compared to the PC-CCS retrofit via post-combustion capture (see Figure 12.41 ), in contrast to the situation for new construction. This is largely because in this application the capital investment is ~three times that for the PC-CCS retrofit (see Table 12.25 ) whereas in new construction, where CIGCC-CCS does offer a lower LCOE, the capital cost for CIGCC-CCS is likely to be less than for a new pulverized coal plant with post-combustion capture (see Figure 12.10 ).

Repowering via NGCC : The natural gas combined cycle power plant venting CO 2 (NCCC-V) is the least capital-intensive and least water-intensive of the options shown in Table 12.25 . But its carbon-mitigation potential (GHGI = 0.42) is far less than what is likely to be required by mid-century to realize the US goal of more than an 80% reduction in the nation’s total GHG emissions. This implies that, if NGCC-V is deployed in the near term as a repowering option at WO PC-V plant sites, the NGCC-V would have to be replaced by NGCC-CCS (as a retro-fit or via repowering option) at some point during this half-century. As shown by Figure 12.41 this option would be roughly competitive with a PC-CCS retrofit, and the energy penalty for CCS and water require-ments would be less than half of those for a PC-CCS retrofit. 42 One serious economic challenge posed by the NGCC-CCS option is that the minimum GHG emissions price needed to induce CCS by market forces is nearly US$100/t (see Figure 12.41 ). Another relates to the prospect that it will be very difficult for NGCC-CCS to defend the high assumed 85% capacity factor in economic dispatch competition if there is much coproduction capacity on the electric grid because of the technology’s high minimum dispatch cost compared to coproduction options (see Figure 12.43 ). 43 Still another problem posed by the NGCC-CCS option is that prospective natural gas supplies in the United States are likely to fall far short of what would be required to meet fully the decarbon-ization challenge posed by existing coal power plants, as discussed in Section 12.6.3.4 .

Repowering via XTL-OT technologies : Though not a decarboniza-tion option (GHGI = 1.18), CTL-OT-V is included here as a repowering option because it offers the least costly electricity at low GHG emissions prices. 44 Its inclusion highlights the GHG emissions prices needed to induce a transition to coproduction systems offering significant reduc-tions in GHG emissions. Notably, for all coproduction options the energy

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Figure 12.42 | Breakeven crude oil price (BEOP) vs GHG emissions price for the alternative coproduction systems in Table 12.25 . (See Table 12.6 , note (b) for fi nancial parameter values assumed.) Source: based on Liu et al., 2011a ; Williams et al., 2011 .

Figure 12.41 | Levelized cost of electricity (LCOE) vs GHG emissions price under US conditions for the alternative power options in Table 12.25 when the levelized crude oil price is US$90/bbl. (See Table 12.6 , note (b) for fi nancial parameter values assumed.) Source: based on Liu et al., 2011a ; Williams et al., 2011 .

42 This may seem surprising because, like the PC-CCS retrofi t, CCS involves post-com-bustion capture and the CO 2 partial pressure in fl ue gases is much lower (0.04 atmospheres). The modest penalty arises in this case because the capture rate is only 0.38 t/MWh compared to 1.17 t/MWh for PC-CCS retrofi t − refl ecting the much lower carbon intensity of natural gas compared to coal.

43 See discussion of dispatch competition in Section 12.6.3.1 .

44 At $0/t its LCOE is the same as for WO PC-V.


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penalty for CCS is one quarter to one half of that for the PC-CCS retrofit, and in all cases water requirements are less than two-thirds as much as for the PC-CCS retrofit. The CCS energy penalty is small largely because a substantial amount of CO 2 must be removed from syngas upstream of synthesis even in the absence of a carbon policy. 45 Water requirements are low for three reasons: (i) the low energy penalty for CO 2 capture; (ii) a significant part of the power output is from the gas turbine part of the power cycle, which does not require water for cooling (as in the NGCC and CIGCC cases); (iii) two thirds or more of the net energy output is in the form of liquid fuels, the production of which requires much less water than does electricity generation.

A notable feature of Figure 12.41 is that the coproduction options with CCS that do not offer deep reductions in emissions (CTL-OT-CCS (GHGI = 0.63) and CBTL1-OT-CCS (GHGI = 0.50)) are never the least costly electricity generation options. Rather, WO PC-V is the least costly option until the GHG emissions price reaches ~US$40/t, above which CBTL-OTA-CCS (GHGI = 0.077) is the least costly option.

It may seem counterintuitive that the more capital-intensive CBTL-OTA-CCS, which involves “aggressive” CO 2 capture, offers a lower LCOE than CBTL-OT-CCS at high GHG emissions prices. There are three reasons for this. First, the average feedstock price for CBTL-OTA-CCS (with 29% bio-mass) is 10% less than for CBTL-OT-CCS (with 40% biomass). Second, the capital intensity (in US$/kW e ) of CBTL-OTA-CCS falls from being 18% higher than for CBTL-OT-CCS when their FTL output capacities are the same to 12% higher when the CBTL-OTA-CCS output capacity is increased to the point where the biomass consumption rates are the same (1 Mt/yr) for these options. The net effect of the lower feedstock price and the higher capital intensity is that the LCOE is only 3% higher

for CBTL-OTA-CCS than for CBTL-OT-CCS at US$0/t. Third, the more rapid rate of decline of LCOE with GHG emissions price for CBTL-OTA-CCS arises because its FTL/electricity output ratio (and thus the credit for GHG emissions avoided by displacing crude oil derived products) is 21% higher for CBTL-OTA-CCS than for CBTL-OT-CCS.

A single XTL-OT plant requires an investment of US$1.2–1.8 billion (see Table 12.25 ). Investors will worry about the risk of oil price collapse, which is a very real concern because marginal oil production costs are lower than US$90/bbl, the assumed oil price for the LCOE calculations presented in Figure 12.41 . In particular, successful market establishment of coproduction technologies could plausibly drive down oil prices.

How might investors be protected against the risk of oil price collapse? To help address this question, Figure 12.42 was constructed to show the breakeven crude oil prices for the alternative coproduction technologies. This figure shows that those who invest in XTL-OT-CCS technologies that coprocess biomass at high rates (29–40%) would be protected against falling oil prices down to less than US$60/bbl if the average GHG emis-sions price were US$69/t, the minimum GHG emissions price needed to make a PC-CCS retrofit competitive with WO PC-V. In contrast, the XTL-OT-CCS options that coprocess no or only modest amounts of biomass offer only modest protection against the risk of oil price collapse. Thus, the combination of a strong carbon mitigation policy and a high rate of biomass coprocessing is key to simultaneously realizing deep reductions in GHG emissions and enhancing transportation fuel security.

Finally, an attractive attribute of XTL-OT systems is their low minimum dis-patch costs (MDCs), which would enable them not only to defend high capacity factors in economic dispatch competition but also would make it possible for them to drive down the capacity factors of competing tech-nologies as XTL-OT market penetration expands. Figure 12.43 illustrates the point for CBTL-OTA-CCS. At crude oil prices of US$37/bbl and US$57/bbl, respectively, this system would have MDCs that are the same as for PC-CCS retrofits and WO PC-V plants when the GHG emissions price is $0/tCO 2 eq. For US$74/bbl crude oil the MDC = US$0/MWh for this system.

12.6.3.4 Repowering Thought Experiment for the United States

The outstanding economics at sufficiently high oil and GHG emis-sions prices of coproduction systems coprocessing coal and substantial amounts of biomass suggest that it would be worthwhile exploring the repowering thought experiment for the United States that follows.

The point of departure for the thought experiment is an assumption that the United States enacts public policy mandating that all coal-fired power plants be retrofitted or repowered at a linear rate over the period 2016–2050, until all existing coal power plant capacity is replaced. Since the projected level of coal capacity for 2015 is 322 GW e (US EIA, 2010b ), the coal power retrofit/repowering rate would be 9.2 GW e /yr during 45 See caption to Figure 12.31 .

Figure 12.43 | Minimum dispatch cost (MDC) vs GHG emissions price for the alter-native coproduction systems listed in Table 12.25 . Source: based on Liu et al., 2011a ; Williams et al., 2011 .


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2016–2050. It is further assumed that market forces are effective in deploying the least-costly options and that crude oil and GHG emissions prices are sufficiently high to make CBTL-OTA-CCS technology the least costly power generation option, and to make both NGCC-V and NGCC-CCS technologies less costly options than both the WO PC-V and PC-CCS retrofit options. (One set of prices for which these conditions would be met is US$90/bbl of crude oil and a GHG emissions price greater than US$50/t, see Figure 12.41 .) Also it is assumed that under repowering con-ditions a site would not produce any electricity for a period of five years, which is the time required to bulldoze the existing site and build a new repowering unit there. Under these conditions, it would be cost-effective to retire WO PC-V plants, no PC-CCS retrofits would be deployed, and the following would be a cost-effective scenario:

During 2016–2020, greenfield NGCC-V plants come on line at a rate of •9.2 GW e /yr to exactly compensate for coal power plant retirements.

During 2021–2050, each year 9.2 GW • e of coal power capacity is replaced by 4.9 GW e of CBTL-OTA-CCS repowering capacity + 4.3 GW e of NGCC-CCS makeup capacity built at greenfield sites to com-pensate for coal plant retirements.

The following are the results of this repowering thought experiment, assuming for simplicity that over the period to 2050 the US energy econ-omy is frozen at the level of energy activities of 2015 as projected in US EIA ( 2010b ) for all energy sectors except coal power:

GHG emissions for 1810 TWh of electricity (all coal electricity in 2015) •would be reduced in 2050 by 1.61 GtCO 2 -eq/yr (85% reduction).

GHG emissions for 5.4 million barrels/day of gasoline equiva- •lent liquid transportation fuels would be reduced in 2050 by 0.84 GtCO 2 -eq/yr (92% reduction), bringing the total GHG emissions avoided in 2050 to 2.45 GtCO 2 -eq/yr.

Replacement electricity generation in 2050 would be made up of •64% CBTL-OTA-CCS, 22% NGCC-CCS, and 14% NGCC-V.

The CO • 2 storage requirements in 2050 would be 2.04 GtCO 2 (93% via CBTL-OTA-CCS and 7% via NGCC-CCS).

The biomass required for CBTL-OTA-CCS plants in 2050 would be •508 Mt/yr.

US coal and natural gas use in 2050 would be, respectively, 19% and •31% higher than in 2009 (see Figure 12.44 ).

The total investment required for the repowering thought experi- •ment through 2050 is US$1.1 trillion (see Figure 12.45 ).

The results of the repowering thought experiment have some important strategic implications:

The low C transportation fuels produced would be at about the •level of transportation fuels produced from US domestic crude oil in 2009 . 46

The total CO • 2 storage requirements in 2050 would be about the same if PC-CCS retrofits were pursued 47 instead of this repowering strategy, even though the retrofit strategy would involving decar-bonising only coal power − a startling result that reflects largely the difference in energy penalties for CCS (36% for PC-CCS retrofits vs 17% and 16% for CBTL-OTA-CCS and NGCC-CCS, respectively, see Table 12.25 ).

The potentially available biomass resources converted using CBTL- •OTA-CCS systems could produce much more low-GHG liquid fuel than if converted to cellulosic ethanol, because producing 1 GJ of

Figure 12.44 | Coal and natural gas demand implications of US repowering thought experiment (RTE).

46 Crude oil was produced in the United States in 2009 at a rate of 5.36 million barrels per day, from which 5.18 million bbl/day of gasoline equivalent transportation fuels (gasoline, diesel, and jet fuel) were produced.

47 In the CCS retrofi t strategy 73% of the system capacity and 97% of the system gen-eration in 2050 are provided by PC-CCS retrofi t plants, while 27% of system capacity and 3% of generation are provided by NGCC-CCS. The CO 2 storage rate in 2050 is 2.08 GtCO 2 , 99% is via PC-CCS retrofi t plants.


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Fischer-Tropsch transportation fuels via CBTL-OTA-CCS requires only 36% as much biomass as producing 1 GJ of cellulosic ethanol (see Figure 12.33 ). If the same amount of synthetic low-carbon liquid fuel as would be produced in 2050 in the repowering thought experi-ment were instead produced as the energy equivalent amount of cellulosic ethanol, some 1400 Mt/yr of biomass would be required (see Section 12.6.4 ). In 2005 it was widely believed that the United States has 1300 Mt/yr of prospective biomass supplies for energy. Concerns about food/fuel competition, indirect land-use impacts, and biodiversity loss have reduced the estimate of sustainable US biomass production to ~500 Mt/y (the level for the repowering thought experiment in 2050) if growing dedicated energy crops on good cropland is not allowed – according to the America’s Energy Future Study of the US National Research Council (AEFP, 2009 ).

The incremental natural gas supply required for the RTE beyond that •for 2009 is 7.5 EJ/yr by 2050 and 5.9 EJ/yr for the intermediate year 2035. The latter is much less than the 9.4 EJ/yr of incremental shale gas which the Energy Information Administration estimates will be available by 2035 (AEFP, 2009 ). However, US EIA also projects sub-stantial reductions for other gas supplies in the period to 2035 (see Figure 12.46 ), so that the net incremental gas supply in 2035 relative to 2009 is only 3.1 EJ/yr, which is enough to satisfy only 52% of the natural gas requirements 48 for the RTE by 2035, assuming all the incremental gas is dedicated to power generation.

Alternative renewable electricity supplies would have to grow four •times between 2009 and 2035 if all of net incremental gas supply projected for 2035 were used for power generation and the short-

fall in electricity generation were provided entirely instead by these renewable sources.

The simple payback on the investment would be ~seven years (see • Figure 12.45 ) if the only benefit considered for this repowering strat-egy were the reduced health damage costs from PM 2.5 air pollution (see Table 12.9 ).

12.6.4 Alternative Approaches for Low GHG-emitting Liquid Fuels Using Biomass

The analysis in the preceding section indicates that coproduction sys-tems with CCS that coprocess ~30% biomass would be very competi-tive as repowering options for sites of old coal power plants at high oil and GHG emissions prices, while simultaneously providing synthetic liquid fuels with near zero net GHG emissions. But biomass is a scare resource. How does this biomass use option compare to other options for providing low-GHG-emitting transport fuels? This question must be addressed to understand better the extent to which biomass coprocess-ing with coal and CCS for coproduction systems should be given prior-ity in public policies relating to future uses of biomass for energy.

To address this question, the CBTL-OTA-CCS option for which 29% of the feed (HHV basis) is biomass is compared to alternative ways to use biomass to provide low-C fuels. Attention is focused on six alternatives. One alternative (BIGCC-CCS) was discussed in Section 12.2.3 . The nega-tive emissions with BIGCC-CCS provide “room in the atmosphere” for emission from some petroleum-derived fuels. Three alternatives (CBTL-RC-CCS, BTL-RC-V, BTL-RC-CCS) were discussed in Section12.4.3. Two new systems not yet considered, are also introduced as alternatives: (i) a future cellulosic ethanol option (EtOH-V), which is currently a high priority for biofuels development in the United States; and (ii) a –CCS variant of this (EtOH-CCS), see Box 12.3 . In total, seven options are

48 Since the natural gas demand for NGCC-V systems deployed during 2016–2020 would have to be satisfi ed fi rst in the RTE, only 15% of the natural gas needed for NGCC-CCS systems by 2035 would be available from net incremental natural gas supplies.

Figure 12.45 | The simple payback on the total new plant investment, 2016–2050, for the RTE would be about seven years if the sole benefi t considered is the reduced public health damage costs from reduced PM 2.5 air pollution. (See Table 12.9 .)


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presented in Table 12.26 . In all cases it is assumed that the feedstock is switchgrass consumed at a rate of about 0.5 Mt/yr dry biomass − the reference scale assumed for future cellulosic ethanol plants (EtOH-V) assessed in a recent United States National Research Council report (AEFP, 2009 ).

Six of the plants listed in Table 12.26 involve CCS, but the CO 2 cap-ture rates vary by a factor of 17 from the lowest (EtOH-CCS) to the highest (CBTL-OTA-CCS). To illustrate the impact of capture rate on system economics it is assumed in all CCS cases that the CO 2 is trans-ported 100 km and stored in a saline formation 2 km underground, and that the maximum CO 2 injectivity is 2500 t/day per well. The CO 2 transport and storage cost model cited by Liu et al. ( 2011a ) is used to estimate CO 2 transport and storage costs (in US 2007 $/t). Alternative biomass use options are compared with respect to five metrics. Three of these are defined and presented for the alternative options in Table 12.26 : a biomass input index (BII), a greenhouse gas emissions index (GHGI), and a zero-emission fuels index (ZEFI). In addition, Figure 12.47 presents the LCOF for the six options that provide fuels,

and Figure 12.48 presents the real internal rate of return (IRRE) for four options.

BII : This index (defined in Table 12.26 , note (c)) indicates that the coprocessing options (CBTL-RC-CCS and CBTL-OTA-CCS) require much less biomass to make low-C liquid fuels than the biofuel options (e.g., 36–40% as much as is required for the EtOH options).

GHGI : All options have outstanding GHG emissions mitigation perform-ance, with GHGI less than 0.20. Four options have negative emission rates that could offset emissions from other fossil energy systems.

ZEFI : This performance index (defined in Table 12.26 , note (e)) highlights the strategic importance of storing underground a large fraction of the biomass feedstock carbon not contained in the energy products, thereby exploiting the negative GHG emissions benefit of photosynthetic CO 2 storage. It quantifies simultaneously the carbon mitigation and liquid fuel insecurity mitigation potentials of an option. The higher the value of ZEFI, the better the option. Four of the options store enough photosynthetic

Box 12.3 | Prospective Cellulosic Ethanol Technologies

EtOH-V : The main cellulosic ethanol option considered here is the future switchgrass-to-ethanol option analyzed in a study by America’s Energy Future Panel (AEFP, 2009 ), for which the estimated yield is 80 gallons of ethanol (EtOH) per dry short ton (334 L/t). For reference, the yield from switchgrass with currently understood technology is ~69 gallons per dry short ton (288 L/t). That study estimated a capital cost of US 2007 $156 million for a plant producing 40 million gallons (156 million liters) of ethanol annually (an output capacity of 1941 bbl/day, or 309,000 L/day, of gasoline equivalent).

EtOH-CCS : It is feasible to carry out CCS for EtOH production if there are adequate CO 2 storage opportunities nearby because in the fermenter 1 mol of CO 2 is generated in a pure stream for each mol of EtOH) produced. The capital cost penalty for this CCS option is modest (see Table 12.26 ).

Shale gas (non-associated, onshore, lower 48)Tight gas (non-associated, onshore, lower 48)Coal bed methane (non-associated, onshore, lower 48)Other non-associatedAssociated, lower 48AlaskaNet imports

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Figure 12.46 | Outlook for natural gas supplies in the United States. To convert cubic feet to cubic meters, divide by 35.3. Source: modifi ed from US EIA, 2010a .


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Figure 12.47 | LCOF vs GHG emissions price for the six alternative low-carbon fuel options listed in Table 12.26 . Also shown are values of petroleum-derived gasoline and an average for gasoline plus diesel corresponding to the proportions of these fuels found in the FTL fl ues in the CBTL and BTL cases (see Table 12.15 , note (a)). (See Table 12.6 , note (b) for fi nancial parameter assumptions. Also, electricity sales are assumed at the US average grid price plotted in Figure 12.10. ) Based on Liu et al., 2011a .

Table 12.26 | Alternative low carbon fuel options − each consuming 457,000 dt/yr biomass a .

Plant name

Capacities

BII c GHGI d ZEFI e

CO 2 stored f , Mt/y (% of

feedstock C stored)

TPC g , million US 2007 $

Inputs Outputs

Fuel, MW, HHV

% biomass, HHV basis

Electricity, MW e

Liquid fuel, barrels/day of gasoline equivalent

(MW, LHV)

EtOH-V 302 100 2.03 1,941 (113) 2.49 0.17 0.33 0 156

EtOH-CCS 302 100 0.62 1,941 (113) 2.49 –0.21 0.49 0.11 (15) 158

BTL-RC-V 302 100 19.3 2,241 (131) 2.15 0.063 0.42 0 408

BTL-RC-CCS 302 100 14.2 2,241 (131) 2.15 –0.95 1.02 0.44 (56) 416

CBTL-RC-CCS 670 45 24.3 4,882 (284) 0.99 0.029 0.97 0.91 (54) 733

CBTL-OTA-CCS 1041 29 131 5,395 (314) 0.90 0.086 0.92 1.70 (65) 939

BIGCC-CCS b 320 100 118 0 – –0.93 0.99 0.71 (90) 398

a Based on Liu et al., 2011a . See also Box 12.3 . b Based on unpublished modeling carried out by the authors of Liu et al., 2011a in a manner that is consistent with the modeling of the systems presented here that make liquid

fuels + electricity, see Table 12.7 (in which the BIGCC-CCS case here corresponds to the switchgrass case in the PEI section of the table). c BII (biomass input index) ≡ Biomass energy (in GJ LHV dry) required to produce 1 GJ of liquid fuel (LHV). d GHGI is the system-wide life cycle GHG emissions relative to emissions from a reference system producing the same amount of power and fuels. The reference system consists of

equivalent crude oil-derived liquid fuels and electricity from a stand-alone new supercritical pulverized coal power plant venting CO 2 . For details, see Table 12.15 , note (c). e ZEFI (Zero-emissions fuels index) ≡ Amount (in GJ) of equivalent zero GHG-emitting liquid fuel provided per GJ of biomass input. f It is assumed that captured CO 2 is compressed to 150 atmospheres, transported via pipeline 100 km to a storage site, and injected into a deep saline formation 2.5 km

underground. g TPC (total plant cost) ≡ “overnight capital cost” (which excludes interest during construction).


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CO 2 to convert (in effect) 92% or more of the biomass energy into useful zero GHG emitting transportation fuel energy. Although the BIGCC-CCS option does not provide liquid transportation fuels, the negative GHG emissions of this option enables it to offset emissions from crude oil-derived products; assuming the crude oil product displaced is gasoline, the ZEFIs for this option is high (0.99). The –V options perform poorly in terms of this metric. Notably, EtOH-CCS also has a relatively low ZEFI, reflecting the fact that only 15% of the C in the feedstock is stored under-ground so that the potential photosynthetic storage benefit is modest.

LCOF : Figure 12.47 shows that at all GHG emissions prices below $120/tCO 2 eq CBTL-OTA-CCS offers the least costly liquid fuel, becom-ing competitive with the crude oil products displaced when the GHG emissions price exceeds US$40/tCO 2 -eq and the crude oil price is US$90/bbl. In contrast EtOH-V requires a GHG emissions price of more than US$95/t to be competitive at this crude oil price. Notably, pursu-ing CCS does not markedly improve the economics of cellulosic etha-nol at high GHG emissions prices – reflecting the relatively modest photosynthetic CO 2 benefit for this option (storing only 15% of the feedstock C).

Although at US$0/t, BTL-RC-CCS is the most costly transportation fuel option, its LCOF declines rapidly with GHG emissions price as a result of its strong negative GHG rate (GHGI = –0.95). This technology can-not compete with CBTL-OTA-CCS until the GHG emissions price exceeds US$120/t. However, in regions where coal coprocessing is not a realistic option, BTL-RC-CCS would become competitive with crude oil derived products for GHG emissions prices > US$67/t when the oil price is US$90/bbl. As noted earlier, World Energy Outlook 2009 estimates that if the world community were on a path to stabilizing the atmospheric concentration of GHG gases at 450 ppmv, the world oil price would be stable during 2020–2030 at US$90/bbl, and if, in addition, there were a

single global carbon trading price, that price would be about US$70/t by 2030 (IEA, 2009b ). Thus it is plausible that in the post-2030 time period BTL-RC-CCS would be cost-competitive in biomass-rich but coal-poor regions if the world community were on this carbon mitigation path.

IRRE : The real IRRE is a good metric for comparing the economics of power-only options with liquid-fuel options. Figure 12.48 shows the IRRE for the BIGCC-CCS option and the two most promising liquid fuel options analyzed here (CBTL-OTA-CCS and BTL-RC-CCS) for three crude oil prices: US$60, US$90, and US$120/bbl. 49 Several conclusions can be drawn from these curves. First, at very high GHG emissions prices, BIGCC-CCS has the highest IRRE. Second, at all three oil prices, CBTL-OTA-CCS has the highest IRRE at low GHG emission prices, and break-even with BIGCC-CCS occurs at a GHG emissions price that increases with the crude oil price: US$46/t at US$60/bbl, US$76/t at US$90/bbl, and US$107/t at US$120/bbl. Third, BTL-RC-CCS will become more profitable than CBTL-OTA-CCS at GHG emissions prices in the range US$125–130/t.

12.6.5 Coal/biomass Coprocessing with CCS as a Bridge to CCS for Biofuels

Establishing in the market over the next 20 years technologies involving coal/biomass coprocessing with CCS for the coproduction of liquid fuels and electricity could plausibly serve as a bridge to widespread biofuels production with CCS in the post-2030 time frame. This is suggested by the analyses of Sections 12.6.3 and 12.6.4 considered together. This is

49 For these options it is assumed that the debt/equity ratio is 45/55 and that electricity is sold at the US average grid price indicated in Figure 12.10 . For other fi nancing assumptions relating to these IRRE calculations see Liu et al., 2011a .

Figure 12.48 | Real internal rate of return on equity (IRRE) for BIGCC-CCS (see Table 12.26 ) and for the FTL options with the lowest LCOF (see Figure 12.47 ) for three levelized crude oil prices. Electricity sales are assumed at the US average grid price plotted in Figure 12.10 . Based on Liu et al., 2011a .


976

an important consideration because biomass supplies in coal-rich coun-tries are relatively limited but are abundant in many coal-poor regions of the world. In coal-poor regions, the economics of liquid fuel produc-tion via thermochemical conversion of biomass with CCS become eco-nomically attractive relative to crude oil-derived products at prospective GHG emissions prices for the post-2030 period if the global community were to pursue stabilization of the GHG concentration in the atmos-phere at 450 ppmv. Moreover, the capital needed to build these plants should become available in a world with carbon trading and high GHG emissions prices. This is likely because not only would these plants be very competitive in providing liquid fuels, but they also would generate huge revenue streams from the sale of carbon credits. 50

12.6.6 Global Coal/biomass Thought Experiment for Transportation

A global coal/biomass thought experiment for transportation is presented to illustrate the carbon mitigation potential for transportation by 2050 via widespread use of low-carbon fuels provided via coal and/or biomass with CCS in many regions. In coal-poor regions this would be accom-plished via BTL-RC-CCS, and in coal-rich regions via CBTL-OTA-CCS. This thought experiment is set in the context of a world in which the growing of dedicated energy crops on cropland is off-limits (Tilman et al., 2009 ) because of concerns about impacts on food prices (Rosegrant, 2008 ) and land-use effects (Fargione et al., 2008 ; Searchinger et al., 2008 ).

It is assumed for the supply side of this thought experiment that the only biomass supplies are residues 51 and mixed prairie grasses grown with minimal inputs on abandoned agricultural lands. The estimated total global biomass supply under these conditions is approximately 6 Gt/yr dry biomass 52 − all of which is assumed to be used in the thought experi-ment. It is assumed that CBTL-OTA-CCS plants use 1 Gt/yr of biomass worldwide and that the rest of the biomass is used in BTL-RC-CCS plants located in coal-poor regions. Many of these plants would be located in developing regions such as sub-Saharan Africa and Latin America.

Dedicating the entire global biomass supply to BTL and CBTL plants is clearly an unrealistic assumption. However, as the preceding analysis has shown, these applications are likely to be hard to beat in terms of both the carbon mitigation per tonne of scarce biomass and economics in a world of high GHG emissions prices and high oil prices. Moreover, such a starkly defined global coal/biomass thought experiment helps to clarify the tradeoffs associated with the allocation of scarce biomass resources.

The demand for global transportation energy in 2050 in the thought experiment is assumed to be essentially that presented for the IEA’s BLUE Map transportation scenario (IEA, 2009a ), an update for the trans-port sector of its earlier projection to 2050 (IEA, 2008b ). 53 A general characterization of the BLUE Map scenario is that it envisages techno-logical change bringing emissions to 50% of the 2005 level by 2050. This includes a strong emphasis on improving energy efficiency but excludes lifestyle changes and modal shifts. It is appropriate to assume an energy-efficient future as a context for exploring the prospects for carbon mitigation via biomass and coal with CCS because, typically, energy efficiency improvement represents “the low-hanging fruit” in carbon mitigation (e.g., see Chapter 10 ) and thus should be given prior-ity. Transportation is also one of the main branching points of different pathways considered in Chapter 17 ; Figure 17.2 shows possible final energy shares for transportation up to 2100 for different transportation system strategies (discussed further in Chapter 17 , Section 17.3.3.4 ).

The challenge for global transportation is to reduce GHG emissions at midcentury by a factor of four relative to the IEA Baseline Projection in order to reduce global emissions by 50% relative to emissions in 2005. As shown in Figure 12.49 , this baseline projection, which involves nearly a doubling of both energy demand and GHG emissions relative to 2005, illustrates the dimensions of this challenge.

In our global coal/biomass thought experiment, while transportation demand in 2050 is essentially that in the BLUE Map scenario, we modify that scenario by excluding some technologies. We are working from the assumption that no plug-in hybrid vehicles, no all-electric vehicles, and no H 2 fuel cell vehicles are included in the light-duty vehicle (LDV) mix in the period to 2050. This is in contrast to the actual BLUE Map scen-ario, which assumes a high penetration of these technologies in the mix by midcentury. 54 Obviously, this exclusion is not a realistic assumption, because these technologies are being heavily promoted by governments. The main reason for the exclusion is to bring to the attention of policy-makers that, as shown in this chapter, deep reductions can be plausibly realized (e.g., via pursuit of CCS for coal and biomass) at attractive pro-duction costs with essentially no costly changes in transportation fuel infrastructures and with evolutionary rather than revolutionary changes

50 For example, at a GHG emissions trading price of $70/tCO 2 -eq, the present worth of the stream of revenues (over the assumed 20-year economic life of the plant) from the sale of carbon emissions credits for the BTL-RC-CCS plant described in Table 12.26 would be equivalent to 73% of the TPC for the plant.

51 Agricultural residues, forest residues, forest thinnings to reduce forest fi re risk and enhance productivity for commercial species, urban wood wastes, municipal solid wastes.

52 In energy terms, the residue supply is assumed for 2050 to be 75 EJ/yr (the global residue supply for energy assumed for 2050 in IEA, 2008b ). The assumed potential supply of biomass grown on abandoned agricultural lands is 32 EJ per year (average yield of 4.3 dry tonnes/yr on 429 million hectares worldwide) based on Campbell et al. ( 2008 ). The total biomass supply, 107 EJ/yr, is 2.3 times total biomass use for energy in 2005. For comparison, the global biomass supply for 2050 in the IEA Blue Map scenario is 150 EJ/yr (which includes biomass grown for energy on cropland), and the maximum biomass resource availability for 2050 is estimated in Chapter 7 to be still higher than this. For perspective, the total assumed global biomass supply (107 EJ/yr) is comparable to total US primary energy use in 2006 (97 EJ/yr).

53 For the IEA Baseline Projection the total number of light-duty vehicles (LDVs) increases three times to 2.15 billion, 2005–2050, air travel increases 3.9 times, and truck freight increases 1.9 times.

54 In 2050 the LDV fl eet in the IEA BLUE Map Scenario (IEA, 2009a ) includes 37% plug-in hybrids, 21% all-electric vehicles, and 25% H 2 hybrid fuel cell vehicles.


977

in automotive engine technologies. In particular, energy-efficient LDVs 55 (e.g., advanced gasoline and diesel hybrid electric vehicles) are empha-sized in our modified BLUE Map scenario. Our hope is that this modified scenario will inspire policymakers to take a more balanced approach toward decarbonizing the transportation sector and to create policies that enable the low carbon transportation technology options that have been the focus of this chapter to compete alongside the technologies that are intensely promoted in current policies.

The resulting liquid fuel demand and supply for global transportation under the modified BLUE Map scenario are shown as the 3 rd and 4 th bars of Figure 12.49 . Total net GHG emissions are zero for global transpor-tation in 2050 under the conditions of the global coal/biomass thought experiment. The liquid fuel supply would be made up of 19% FTL via CBTL-OTA-CCS, 38% FTL via BTL-RC-CCS, and 43% crude oil–derived products. The level of crude oil-derived products used in transportation

is 51% of the amount of crude oil derived products used for transporta-tion worldwide in 2005. The projected GHG emissions are zero despite the large share of crude oil-derived products in the mix because it is assumed for the thought experiment that the negative emissions from BTL-RC-CCS systems are used to offset positive GHG emissions from both crude oil-derived products and CBTL-OTA-CCS systems.

In 2050 coal use for the modified BLUE Map scenario (with the global coal/biomass thought experiment) is 1.15 times global coal use in 2005, compared to 0.78 times for the IEA BLUE Map scenario and 3.04 times for the IEA Baseline Scenario.

Under the conditions of the thought experiment, CO 2 storage would be carried out in 2050 at rates of 3.7 Gt/yr for CBTL-OTA-CCS plants and 4.8 Gt/yr for BTL-RC-CCS plants. This finding highlights the importance of ascertaining the extent to which there are good geological CO 2 stor-age opportunities in biomass-rich but coal-poor regions, where consid-eration of CCS as a carbon mitigation option has probably not been given much thought.

Is it plausible that about ten thousand BTL-RC-CCS plants 56 might be up and running by 2050 (each processing 0.5 Mt of biomass annually)? If one imagines starting with 20 such plants by 2030 the annual average

55 In the IEA ( 2009a ) scenarios, average fuel economies for new LDVs in 2050 are 5.9 liters of gasoline equivalent per 100 km (l ge /100 km) or 40 miles per gallon of gas-oline equivalent (mpg ge ) for the Baseline Scenario and 2.9 l ge /100 km (81 mpg ge ) for the BLUE Map scenario. The average fuel economy assumed for the entire LDV stock in 2050 in the modifi ed BLUE Map scenario is 2.9 l ge /100 km (62 mpg ge ), which is consistent with the IEA assumptions for the average fuel economy for new LDVs in the actual BLUE Map scenario. There are reasonable prospects that this average fuel economy for the LDV stock could be realized without use of plug-in hybrids or fuel cell vehicles. Kromer and Heywood ( 2007 ) have estimated that by 2030 a mid-sized conventional hybrid-electric car (essentially a 2030 version of a Prius) could have a fuel economy of 3.1 l ge /100 km (76 mpg ge ).

56 Each of which provides 2,200 bbl/day of gasoline equivalent FTL + 14 MW e of elec-tricity and requires an investment of US$420 million (see Table 12.26 ).

0

20

40

60

80

100

120

140

160

180

200

220

2005 2050 IEA

Baseline

2050 IEA

Blue Map (modified)

2050 Supply

Blue Map (modified)

Biomass Input

0

20

40

60

80

100

120

140

160

180

200

220

2005 2050 IEA

Baseline

2050 IEA

Blue Map (modified)

2050 Supply

Blue Map (modified)

Biomass Input

Lightduty

vehicles

Trucks

Passenger

air

Marine Freight

Crude oil-

derived pro-

ducts

BTL-RC-CCS

CBTL-OTA-CCS

Grasses onabandonedcropland

Other

Residues

Global Transporta�on Energy Demand Liquid

Fuel

Supplies

Required

Biomass

LDV fuel use rate

Ener

gy (E

J/yr

)

(liters ge/100 km) 12.6 8.76 3.78

7.3 0.0

14.2

Figure 12.49 | Energy and GHG emissions for global coal/biomass thought experiment and for IEA 2050 Baseline (business-as-usual) scenario. Numbers at tops of bars are total GHG emissions in GtCO 2 -eq/yr. LDV fuel use rate is in liters of gasoline equivalent per 100 km. Source: see discussion in text.


978

growth rate in plant deployment, 2030–2050, would have to be 37%/yr. This extraordinarily high growth rate would not take place without sup-portive public policy, but it is not inconceivable. In its heyday, nuclear power grew worldwide at a sustained average growth rate of 37%/yr from 1957–1977.

Much of this growth would take place in now-impoverished developing countries, where this technology would represent a major opportunity for industrial growth. But many such countries currently have neither the needed physical infrastructures (e.g., roads, railroads, pipelines, port facilities for managing exports, etc.) nor the human capacity to man-age such industrial growth. The technology is not likely to be cost com-petitive until about 2030 even under strong carbon-mitigation policies worldwide, however, so there is a strategic opportunity to build those needed capacities in the interim − if the global community comes to think that there is a pressing need for this industry.

Finally, if the goal for decarbonizing global transportation were to reduce by 2050 GHG emissions for transportation worldwide not to zero but rather to half the 2005 level (in line with current long-term policy goals for carbon mitigation), the global biomass requirements for 2050 drop to a level that is only 38% higher than global biomass use in 2005 – so that considerable biomass would be available for purposes other than to satisfy the global coal/biomass thought experiment needs. Moreover, crude oil-derived prod-ucts (in an amount equivalent to 69% of the level for transportation in 2005) would account for 60% of total transportation energy in 2050.

12.7 Long-term Considerations

The preceding analyses in Chapter 12 focused mainly on technologies that are near at hand. It is beyond the scope of Chapter 12 to present a comprehensive review of advanced fossil energy conversion tech-nologies. Rather, the focus in this short section is on some advanced technologies that might be especially helpful in evolving to promising longer-term future low-GHG emitting fossil-fuel-based electricity and synfuels technologies and strategies.

12.7.1 Low-carbon Electricity Generation Technologies in the Long-term

For systems that provide only electricity, a brief review is presented of prospects for substantial cost reduction in systems with CCS. The review is restricted to gasification-based systems for three reasons. First, with cur-rent bituminous coal technologies, CIGCC systems with pre-combustion CO 2 capture outperform PC systems with post-combustion capture – as shown in Section 12.2.3 . Second, synfuel/electricity coproduction sys-tems that require gasification have astonishingly good economic pros-pects even with current technologies, as discussed in Section 12.6.3 . Reason number three has to do with the fact that coal gasification tech-nologies are at a much earlier stage in their technological evolution than

are coal combustion technologies. Over the longer term, it is plausible that conversion efficiencies will be higher and costs for generating coal electricity with CCS will be lower with advanced gasification technolo-gies than the costs presented in detail in earlier sections of Chapter 12 .

A recent report from the US National Energy Technology Laboratory gives a sense of the possibilities: Gray et al. ( 2009 ) describe two alternative technological paths for gasification energy to provide power from coal with CCS: (i) an evolutionary change path that involves a series of incre-mental changes in CIGCC technology and (ii) a revolutionary change path that involves a shift from combustion energy conversion to elec-trochemical energy conversion via use of solid oxide fuel cells (SOFCs). Here key findings of Gray et al. ( 2009 ) are sketched out to highlight the importance of a major research and development effort in this area.

The evolutionary change approach for CIGCC involves the following incremental changes over time:

a continuation of the historical trend toward improved gas turbine •performance as a result of increasing firing temperatures and higher pressure ratios, but with emphasis in a carbon-constrained world on gas turbines burning hydrogen;

introduction of a dry coal feed pump to reduce the energy penalty •associated with evaporating water via a coal/water slurry feed sys-tem and to provide a simplified alternative to the lockhopper dry feed systems currently used;

warm acid gas removal with CO • 2 capture in Selexol instead of the current cold CO 2 capture in Selexol, to greatly reduce the energy pen-alty otherwise required for Selexol regeneration;

warm acid gas removal with H • 2 and CO 2 separation via a hydrogen separating membrane that delivers hydrogen in a pressurized N 2 /H 2 mixture to the gas turbine combustor while enabling CO 2 recovery as a separate stream at elevated pressure, thereby reducing the CO 2 compressor load;

use of an ion transport membrane • 57 instead of a cryogenic air separ-ation unit to provide O 2 for the gasifier − the main impact of which would be to reduce the capital cost for O 2 production;

increased system reliability, availability, and maintainability – result- •ing in an increased system capacity factor.

Gray et al. ( 2009 ) carry out a systems analysis suggesting that success in all of these areas over time could plausibly lead, for US conditions, to

57 A non-porous ceramic membrane through which O 2 ions fl ow at high temperature (800–900°C) and are converted to O 2 molecules on the permeate side of the mem-brane, while electrons fl ow countercurrent to the retentate side of the membrane.


979

an eventual IGCC-CCS efficiency ~40% (HHV basis) and a capital cost (TPC) less than US$1700/kW e – values very similar to the corresponding values for new supercritical steam-electric plants in the US today (the PC-V option described in Section 12.2.2 ).

The revolutionary SOFC approach involves coupling a high-efficiency SOFC operating at pressure to a catalytic gasifier that produces meth-ane-rich syngas, such as the gasifier being developed by Great Point Energy (a company in the United States) for making substitute natural gas. 58 As the syngas passes through the anode of the SOFC the methane is reformed with steam to form CO and H 2 , and these gases in turn react with steam and oxygen to form CO 2 and H 2 O while providing elec-tric power for the external circuit. Part of the heat released in these reactions is manifest as a rise in the syngas temperature from 600°C to 900°C as it passes through the anode. The oxygen is provided as O 2 – ions (undiluted with nitrogen) via transport through the fuel cell’s non-porous ceramic membrane electrolyte 59 from the hot air streaming through the cathode. The benefits of this approach to power generation (Grol et al., 2007 ) include the following:

Making electricity directly from chemical energy without first having •to burn the fuel to make heat gives rise to higher energy conversion efficiency than can be realized via fuel-powered heat engines.

The lower gasification temperature of the catalytic gasifier means •that less energy is needed to heat the gas to its operating tempera-ture, so that the gasification efficiency is higher.

Another benefit is energy and cost savings, given the fact that with •a sufficiently high fraction of methane in the gasifier-generated syn-gas, the methanation reaction exotherm can provide enough heat for gasification – which implies significant energy and cost savings associated with air separation that would otherwise be needed to provide oxygen for gasification.

The SOFC produces steam when H • 2 in the syngas and pure O 2 react on the anode; the steam reacts with methane in the syngas produ-cing CO and H 2 ; the CO reacts with more steam to produce H 2 and CO 2 , so that what ultimately leaves the system is a stream of CO 2 and H 2 O − from which CO 2 is easily separated for piping to an under-ground storage reservoir.

The strong endotherm of the methane steam reforming reaction on •the anode absorbs a considerable amount of heat released from the oxidation of H 2 to produce water, thereby reducing the amount

of air required to cool the SOFC − one manifestation of which is a reduction of the amount of air compression that would otherwise be required to provide this cooling air.

If the SOFC operates at an elevated pressure, the subsequent CO • 2 compression required for pipeline transport to suitable storage sites would be less than if the SOFC operates at atmospheric pressure.

The steam reforming of methane on the anode eliminates the need for •a separate steam reformer when methane-rich syngas is the feed.

The “shifting” of CO to CO • 2 by reaction on the anode with water, producing H 2 , eliminates the need to shift CO to CO 2 in a separate “water-gas-shift” reactor.

Gray et al. ( 2009 ) have estimated prospective efficiency, capital cost, and levelized electricity production costs for such SOFCs and compared them to the same quantities that would arise with the evolutionary strategy. They found that the system efficiency would be 40% higher (~56%), the specific capital cost (US$/kW e ) would be ~5% higher and the lev-elized cost of electricity would be about the same − although perhaps requiring a longer period of time to achieve such estimated performance and cost values. Many of the technological advances analyzed would be applicable to systems that coproduce synthetic fuels and electricity, as described for current technologies in Section 12.6 . These findings sug-gest that both the evolutionary and the revolutionary approaches war-rant comparable levels of research and development support. It does not necessarily follow, however, that these two approaches would offer comparable overall benefits when the technologies involved are fully developed.

12.7.2 Technologies and Strategies for Low-carbon Liquid Fuels in the Long-term

Maintaining the option of sustaining liquid hydrocarbon fuels as the pri-mary energy carriers for the transportation sector even under a severe carbon policy constraint is extraordinarily important in light of the ease of transporting, storing, and using these fuels compared to the alterna-tives such as H 2 and electricity (e.g., see near the end of Section 12.4.4 for some discussion of the challenges for evolving a ground transporta-tion system based on hydrogen fuel cell vehicles).

In the earlier Chapter 12 analysis of opportunities for producing syn-thetic fuels characterized by low greenhouse gas emission rates, some of the most important findings were the strategic importance of:

CCS for biomass as a carbon mitigation strategy for a carbon-con- •strained world;

the opportunity to get started with CCS for biomass via coal/biomass •coprocessing; and

58 Based on the original Exxon process, Great Point Energy’s catalytic gasifi er is a relatively low-temperature gasifi er that involves the production of methane as a considerable fraction of the syngas output as a result of a potassium-catalyzed methanation reactions.

59 The SOFC electrolyte permits the fl ow of O 2 ions (like the ceramic non-porous ion transport membrane mentioned above for O 2 production) but does not permit elec-trons to fl ow in the reverse direction.


980

electricity + synfuels coproduction w/CCS as a critical path for •coprocessing in realizing simultaneously:

Low costs for low-C electricity; •

Low costs for low-C synfuels; •

Energy insecurity mitigation in a manner consistent with realiza- •tion of carbon-mitigation objectives.

Chapter 12 points out that first generation technologies based on these novel concepts can be deployed in the market during the current dec-ade. Much can be done to improve such systems using advanced tech-nologies. Although a systematic review of advanced concepts is beyond the scope of the present analysis, what is discussed here is of possible strategic importance:

a new approach to chemical synthesis in the context of a carbon •constrained world;

shale gas for a carbon-constrained world; and •

extension of the coproduction concept from the present focus on •coal/biomass coprocessing to include as well natural gas/biomass coprocessing.

12.7.2.1 Synthesis chemistry for a carbon-constrained world

The chemical process industry and the embryonic synfuels industry are based on making synthesis gas (mainly CO and H 2 ) from a fossil fuel and/or biomass and then combining the synthesis gas molecules CO and H 2 to make chemicals and/or fuels. A recent paper (Hildebrandt et al., 2009a ) points out that there are potentially significant gains in energy conversion efficiency to be exploited by shifting both the gasification process from the production of mainly CO and H 2 to the production of instead mainly H 2 and CO 2 and basing the subsequent chemical syn-thesis on combining H 2 and CO 2 instead of H 2 and CO. Applying the idea to the production of F-T liquids from coal via gasification, those authors point to an 18% theoretical potential reduction in the amount of net work required for the overall process and a 15% reduction in the amount of coproduct CO 2 generated in the process. 60

This idea might be helpful in the context of a carbon mitigation policy, for evolving from the present situation where energy is based mainly on fossil fuels, to an energy future in the very long term when synthetic liquid hydrocarbon fuels might be made mainly by combining H 2 derived from water using a non-carbon primary energy source 61 such as solar energy or thermonuclear fusion, and CO 2 extracted directly from the air 62 to make liquid fuels − a process that might start with methanol production:

CO 2 + 3 H 2 → CH 3 OH + H 2 O, (6)

followed by conversion of the methanol to hydrocarbon liquid fuels such as gasoline via the already commercial MTG processes (see Sections 12.4.1.2 and 12.4.3.1 ) or via future processes that would produce mid-dle distillates as well as gasoline (Keil, 1999 ).

Though seemingly different in the case of methanol production from the present approach that involves making methanol from syngas via:

CO + 2H 2 → CH 3 OH, (7)

it is now well known (Hansen, 1997 ) that what really happens in making methanol from syngas is that CO first reacts with H 2 O to form CO 2 and H 2 via the water gas shift reaction followed by the hydrogenation of CO 2 on the catalyst surface. Moreover, making methanol from CO 2 and H 2 is actually not a novel approach. 63

At present H 2 produced from non-carbon energy sources is far more costly than making H 2 with ultra-low GHG emissions from coal or nat-ural gas with CCS (Williams, 2002 ), and direct extraction of CO 2 from the air is far from being economic. 64 Nevertheless, the concept of making chemicals and synfuels from CO 2 + H 2 could potentially be of strategic importance even in the near term in fossil fuel and fossil/biomass sys-tems that make synfuels (or synfuels + electricity) and produce CO 2 as a major coproduct. Under a serious carbon policy constraint, the excess CO 2 has to be captured and stored underground in any case; a key insight implicit in the Hildebrandt analysis (Hildebrandt et al., 2009a ; Hildebrandt et al., 2009b ) is that there may be strategic advantages of using this readily available CO 2 to improve overall energy system per-formance before delivering the excess to underground storage.

This discussion ends with a word of caution. The importance of potentially improving system efficiencies by exploring gasification and synthesis

60 An e-letter comment on the Hildebrandt et al. ( 2009a ) paper by Desmond and Gibson ( 2009 ) points out that at the high gasifi cation temperature considered it is not practical to design a gasifi er that produces mainly H 2 and CO 2 unless an enormous amount of water is added to promote the water-gas-shift reaction, but the energy penalty of heating that water would eliminate potential energy savings. Hildebrandt et al. ( 2009b ) responded that it would be practical to produce mainly H 2 and CO 2 if one considers not a single piece of equipment but rather a gasifi er followed by a water-gas-shift reactor operated at a much lower temperature than the gasifi er. But if that were done it is not clear how one could realize energy savings for the gasifi cation part of the system, although there would still be signifi cant sav-ings by basing synthesis on CO 2 + H 2 . Moreover, the GHG emissions associated with the water heating referred to in the Desmond and Gibson ( 2009 ) criticism could be mitigated by heating the water with solar energy instead of burning fossil fuel.

61 See, for example, Lewis and Nocera ( 2006 ) and OSL ( 2003 ).

62 See, for example, Section 2.1.4: Carbon dioxide capture from ambient air, in The Royal Society ( 2009 ).

63 Olah et al. ( 2009 ) point out that the very fi rst methanol plants operating in the 1920s and 1930s were commonly using CO 2 and H 2 from other processes to make methanol.

64 In a recent report of the American Physical Society, it is estimated that with current technology direct air capture of CO 2 would cost $600 or more per tonne of CO 2 , under optimistic assumptions (APS, 2011 ).


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based on CO 2 chemistry should not be construed as suggesting that CO 2 reuse to make synthetic fuels is a viable alternative to CCS.

There is widespread interest in CO 2 reuse for making industrial products as an alternative to CCS. For example, the US Department of Energy has dedicated more than US$107 million to the exploration of twelve approaches to reuse (DOE, 2010 ). Of these concepts, the most numer-ous and globally significant are systems that use microalgae to cap-ture CO 2 from power plant flue gas and convert it (via sunlight, water, and nutrients) into natural oils that are readily processed into liquid transportation fuels such as biodiesel. The concept is tantalizing when one considers, as an example, that the United States in 2008 consumed fossil fuel carbon in the amounts of 500 Mt in the form of transporta-tion fuels while simultaneously emitting 540 Mt from pulverized coal steam electric power plants. If the CO 2 in flue gases were captured and reused by being converted into carbonaceous liquid fuels using solar energy or another non-carbon energy source to provide the needed pro-cess energy, enormous quantities of transportation fuels could be pro-vided without increasing GHG emissions. But this example contains the essence of the shortcomings of reuse to make transportation fuels: If, hypothetically, 100% of the CO 2 from flue gases of US coal power plants were converted via carbon-free energy sources into transportation fuels, the carbon emissions for the system of making both transportation fuels and electricity from coal would be reduced by only 50% from the level of the current system that makes electricity from coal with CO 2 venting and transportation fuels from crude oil.

Kreutz ( 2011 ) examines two cases to estimate the potential for GHG emissions reduction via reuse of coal power plant CO 2 to make liquid transportation fuels: the growing of algae in algal ponds to make bio-diesel and the use of concentrated sunlight to reduce CO 2 to CO and O 2 and/or H 2 O to H 2 and O 2 to make liquid fuels via Fischer-Tropsch synthesis. He shows that the carbon mitigation potential of reuse strategies to make synthetic transportation fuels is at best very modest in a world where the carbon price is high enough to induce decarbonization of coal power plants either by shifting to a carbon-free or low-carbon power source or by making CCS more economical than venting CO 2 (in which case the CO 2 would be captured and available mainly in pipelines to underground storage sites so that its diversion from this purpose would be equivalent to extracting CO 2 from underground). 65 According to Kreutz: “Using the carbon twice fails to meet the objective of deep GHG emission reductions across the entire energy economy; only one sector (either power or trans-portation) – but not both – can claim the benefit of carbon neutrality.” Thus CO 2 reuse strategies to make synthetic fuels would not enable the deep (over 80%) reductions in GHG emissions that leaders of industrial-ized countries are targeting for their countries by midcentury.

12.7.2.2 Implications of Abundant and Ubiquitous Shale Gas

It is truly remarkable how fast views of the fossil fuel energy future change. In its 2003 report to the US Secretary of Energy, the National Petroleum Council (NPC, 2003 ) predicted that future North American natural gas supplies would be flat or declining. In sharp contrast, there is currently much bullishness about the future prospects of shale gas, largely as a result of applications of new effective, economic hydraulic fracturing and horizontal drilling technologies. 66 It is now thought that natural gas extracted from shale in sedimentary basins might turn out to be abundant and ubiquitous, with reasonable production costs. Although most empirical data are from the United States, there is much optimism that the judgments that are now being formed about US shale gas pros-pects might be more or less valid for sedimentary basins throughout the world (see Chapter 7 ).

If this bullishness about shale gas proves to be sound, and growing environmental concerns associated with extraction of shale gas (Rahm, 2011 ) can be addressed, it has potentially far-reaching implications for the future of fossil fuel energy in a carbon-constrained world.

To begin, CCS would need to be pursued for NG energy conversion sys-tems based on shale gas in order to meet carbon mitigation obligations over the longer term. Consider first use of shale gas for making electri-city in NGCC-CCS plants. One advantage offered relative to CIGCC-CCS plants is that less than half as much CO 2 would have to be stored per MWh. Moreover, the capital investment required to generate electricity via NGCC-CCS is likely to be less than half that for a CIGCC-CCS plant having the same output capacity, and the LCOE for such a plant is likely to be less than for a CIGCC-CCS plant at the GHG emissions price needed to make a CIGCC-CCS plant cost competitive with a PC-V plant for nat-ural gas prices up to four times the coal price. 67 The downside for the NGCC-CCS system is that the GHG emissions price required to induce a shift from NGCC-V to NGCC-CCS is very high (see Figure 12.10 ).

12.7.2.3 Gas/biomass to Liquids and Electricity with CCS

Should shale gas prove to be as abundant and ubiquitous as some believe, it will be of interest to consider the merits of using shale gas for liquid fuels production. The high breakeven GHG emissions price required to induce CCS for gas-based power generation could be greatly reduced while simultaneously making it possible to realize deep reductions in GHG emissions for synthetic liquid fuels if natural gas were coprocessed

65 This is in contrast to the case at low carbon prices, when using CO 2 from fl ue gases is equivalent to extracting CO 2 from the atmosphere, because a profi t-motivated power generator would rather vent the CO 2 to the atmosphere and pay the emissions fi ne than invest in CCS.

66 There are fundamental differences in the production of gas from shale and from other unconventional sources such as tight sands (Frantz Jr. and Jochen, 2005 ). The latter yield a tremendous amount of gas for the fi rst few months, but then produc-tion declines signifi cantly and often becomes uneconomic after a relatively short time. In contrast, shale gas wells do not come on as strong as gas from tight sands but, once production stabilizes, the wells will produce consistently for 30 years or more.

67 For a coal price of US$2.0/GJ.


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with biomass to make liquid fuels + electricity with CCS − analogous to the CBTL-OT-CCS and CBTL-OTA-CCS systems discussed in Section 12.6 .

Liu et al. ( 2011b ) present analysis of systems coproducing FTL and elec-tricity from natural gas and from natural gas + biomass (switchgrass). Two of the systems analyzed are described in Table 12.27 . The GBTL-OT-CCS option (see Figure 12.50 ), which provides 300 MW e of net electricity + 9750 bbl/day of FTL transportation fuels, was designed to coprocess enough biomass (34%) to reduce GHGI to 0.10. The output capacities of the system were determined by the design criterion that the system con-sumes 1 Mt/year dry biomass. Its system features are compared to the same system without CCS (GBTL-OT-V) and two coal based systems that also coprocess 1 Mt of biomass annually: CBTL-OTA-CCS, which coproc-esses 29% biomass to realize GHGI = 0.0855 (discussed in Section 12.6.3.3 (see Figure 12.31 )), and a variant without CCS.

Notable differences between the natural gas-based and coal-based coproduction systems can be gleaned from Table 12.27 :

The natural gas-based systems convert 34.5% of the feedstock C •to FTL compared to 24.2% for the coal-based systems − a conse-quence of the much lower H/C ratio for coal compared to natural gas (0.8 vs 4.0);

The FTL output amounts to 34.4% of input energy for natural gas- •based systems compared to 32.5% for coal-based systems, showing that the low rate of carbon conversion in the coal case is largely compensated for by the water gas shift reaction, which entails a rela-tively minor energy penalty;

The CO • 2 storage rate for GBTL-OT-CCS is only half that for CBTL-OTA-CCS, reflecting both the lower H/C ratio for coal and the fact that the latter option vents as CO 2 only 6.6% of the C in the feedstock compared to 12.4% in the GBTL-OT-CCS; and

The GBTL-OT-CCS option is much less capital intensive than the •CBTL-OTA-CCS option.

Figure 12.51 presents the levelized cost of electricity (LCOE) vs GHG emissions price for these four options along with the LCOEs for four stand-alone power plants (discussed in Section 12.2.2 ), assuming for all cases that: (i) the levelized fuel prices are US$2.04/GJ HHV , US$5.1/GJ HHV , and US$5.0/GJ HHV for coal, natural gas, and biomass, respectively (see note (b) of Table 12.6 for additional financial parameter assumptions), (ii) a US$90/bbl crude oil price, and (iii) the captured CO 2 that is pres-surized to 150 atmospheres is transported via pipeline 100 km and stored in a deep saline formation 2 km below ground with a maximum injectivity per well of 2500 t/day. The important results from this set of curves are:

Compared to other stand-alone power plants, the GBTL-OT-CCS •option has outstanding performance under a carbon policy constraint,

having breakeven GHG emission prices of: US$25/t in competing with sup PC-V, US$28/t in competing with NGCC-CCS, and US$47/t in competing with NGCC-V; moreover, GBTL-OT-CCS would be able to compete with CIGCC-CCS even at $0/t. For comparison the break-even GHG emissions price for NGCC-CCS competing with NGCC-V is about US$83/t.

At the assumed reference feedstock prices GBTL-OT-CCS is not com- •petitive with CBTL-OTA-CCS.

However, the relative competitiveness between the natural gas- •based and coal-based coproduction systems depends sensitively on the relative coal and natural gas prices. For example, at a GHG emis-sions price of US$0/t the LCOEs for these two coproduction options with CCS would be equal with a modest decrease of 8% in the assumed natural gas price (to US$4.7/GJ HHV ) and a modest increase of 8% in the assumed coal price (to US$2.19/GJ HHV ).

Finally, a global gas/biomass thought experiment for transportation is constructed in the same spirit as the global coal/biomass thought experiment for transportation presented in Section 12.6.6 to illustrate how zero net GHG emissions for transportation in 2050 might be real-ized via widespread deployment of a combination of GBTL-OT-CCS + BTL-RC-CCS systems instead of CBTL-OTA-CCS + BTL-RC-CCS systems, assuming the same demand levels as in the global coal/biomass thought experiment presented in Figure 12.49 .

A comparison of some attributes of the two global thought experiments is presented in Table 12.28 . This table shows that overall production rates for FTL fuels, the amounts of crude oil products used, the total GHG emissions avoided in displacing conventional fossil fuels, and electricity generation rates are comparable for the two thought experi-ments. The amount of coal used in the coal/biomass thought experiment (which produces a larger fraction of FTL via coproduction) is 25% more than the amount of gas used in the gas/biomass thought experiment. The amount of CO 2 storage required with natural gas is only 80% of that for coal, reflecting in large part the lower carbon content of natural gas compared to coal.

The relative roles of coal-based and natural-gas based systems will vary from region to region depending on relative coal and natural gas prices. Despite the bullishness about shale gas in the United States, total US domestic gas supplies are not likely to be adequate to sup-port a substantial role for GBTL-OT-CCS. This conclusion is suggested by the analysis in Section 12.6.3.4 . However, the finding presented in Table 12.28 that total worldwide natural gas use in the modified BLUE Map scenario (which includes the natural gas used for the glo-bal gas/biomass thought experiment) is only 0.81 times the projected worldwide natural gas use in the IEA Baseline Scenario − suggests that at the global level gas supplies might be adequate for realization of the global gas/biomass thought experiment. In any case, the poten-tial benefits of the gas/biomass coproduction option as indicated in


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Table 12.28 suggest the importance of exploring further gas/biomass coproduction systems − which might offer a key to exploiting abun-dant and ubiquitous shale gas in a carbon-friendly manner. However, environmental concerns about “fracking” technologies used for shale

gas recovery with respect to protection of water (Osborn et al., 2011 ) and soil (Jones, 2011 ), as well as concerns about life cycle GHG bal-ances for shale gas (Howarth et al., 2011 ), need to be addressed effectively.

Table 12.27 | Performance and capital cost (US 2007 $) estimates for coproduction systems with biomass/fossil fuel coprocessing.

CBTL-OT-V CBTL-OTA-CCS GBTL-OT-V GBTL-OT-CCS

Input capacities

Coal, as-received mt/day (MW HHV ) 5150 (1616) 5150 (1616)

Natural gas, mt/day (MW HHV ) 2084 (1278) 2084 (1278)

Biomass, as-received mt/day (MW HHV ) 3581(660.5) 3581(660.5) 3581(660.5) 3581(660.5)

Biomass % of total input, HHV basis 29.0% 29.0% 34.1% 34.1%

Output capacities

Synthetic diesel + gasoline, MW LHV (bbl/d crude oil products displaced)

687 (10,882) 687 (10,882) 619 (9,752) 619 (9,752)

Diesel fraction of FTL (LHV basis) 0.634 0.634 0.669 0.669

Gasoline fraction of FTL (LHV basis) 0.366 0.366 0.331 0.331

Gross electricity production, MW 521.1 465.9 484.0 430.5

Net electricity exports, MW 407.8 287.4 384.5 300.2

FTL/Electricity output ratio 1.69 2.39 1.61 2.06

ENERGY RATIOS (HHV basis)

Liquid fuels out /Energy in 32.5% 32.5% 34.4% 34.4%

Net electricity/Energy in 17.9% 12.6% 19.8% 15.5%

Fuels + electricity/Energy in 50.4% 45.1% 54.2% 49.9%

C input as feedstock, kgC/sec 54.5 54.5 34.4 34.4

C stored as CO 2 , % of feedstock C 0 65.5 0 51.7

C in unburned char, % of feedstock C 3.7 3.7 1.4 1.4

C vented, % of feedstock C 45.0 6.6 64.0 12.4

C in FTL, % of feedstock C 24.2 24.2 34.5 34.5

C stored, MtCO 2 /yr a 0 3.71 0.0 1.85

GHGI b 0.903 0.0855 0.539 0.105


Air separation unit + O 2 /N 2 compressors 243 255 217 216

Biomass handling and gasifi cation 335 335 295 295

Coal handling and gasifi cation 396 396 - -

Syngas cleanup 180 215 153 197

NG handling - - 4.0 4.0

CO 2 compression 1.6 33 0 21

F-T synthesis & refi ning 208 208 204 203

Naphtha upgrading 35 35 31 31

Autothermal reformer 0 55 87 87

Power island gas turbine 98 86 92 94

Heat recovery and steam cycle 224 168 154 166

Total plant cost (TPC), million US 2007 $ 1,720 1,786 1,236 1,313

Specifi c capital cost, US 2007 $/kW e 4,218 6,215 3,213 4,375

a With plant operating at 90% capacity factor. b GHGI is the system-wide life cycle GHG emissions relative to emissions from a reference system producing the same amount of power and fuels. The reference system consists of

electricity from a stand-alone new supercritical pulverized coal power plant venting CO 2 plus equivalent crude oil-derived liquid fuels. See Table 12.15 , note (c), for details.


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12.8 Strategies and Policies for Radically Transforming the Fossil Energy Landscape

The analysis in this chapter shows that a radical transformation of the fossil energy landscape is feasible for simultaneously meeting the multiple societal objectives of wider access to modern energy carriers, reduced air pollution health risks, enhanced energy security, and major GHG emissions reductions.

12.8.1 Strategies for a Radical Transformation

Developing countries have quite different economic circumstances at present and hence different energy priorities from industrial-ized countries. The strategies for fossil energy development in developing and industrialized countries will, accordingly, be dif-ferent in the short term, but necessarily must be convergent in the long term.

Autothermal reformer Refinery H 2 prod .

Power island

finished gasoline & diesel blendstocks

flue gas

net export electricity

unconverted syngas + C 1 - C 4 FT gases

light ends oxygen steam

syngas

Water gas shift

C O

2 r e m o v a l

CO 2 enriched streams , sent to upstream CAP .

steam

FT synthesis

Chopping & Lock hopper

oxygen steam

CO 2

FB gasifier & Cyclone

Dry ash

Filter CO 2 removal unit

CO 2 H 2 make - up


Power island

finished gasoline & diesel blendstocks

flue gas



oxygen steam

syngas

Water gas shift

C O

2 r e m o v a l


steam

FT synthesis

Chopping & Lock hopper

oxygen steam

CO 2


Dry ash


CO 2


F - T refining

H C

r e c o v e r y

raw FT product

Power island

syncrude finished gasoline & diesel blendstocks

flue gas



Natural gas

oxygen steam

syngas

Water gas shift

C O

2 r e m o v a l


steam

FT synthesis

Chopping & Lock hopper Biomass

oxygen steam

CO 2


Dry ash


CO 2 H 2 make - up

Figure 12.50 | GBTL-OT-CCS system that provides electricity + FTL (via use of a cobalt catalyst) from natural gas and biomass. Natural gas is converted to syngas in an auto-thermal reformer. Syngas is generated from biomass in a fl uidized bed gasifi er. The autothermal reformer is also used to crack (i.e., eliminate) the tars from the biomass-derived syngas. 52% of C in the feedstocks is captured, compressed to 150 bar, and sent via pipeline to a geological storage site. The system was designed with enough biomass coprocessing (34%) to realize GHGI = 0.10. Source: based on Liu et al., 2011b .

Figure 12.51 | Levelized cost of electricity vs GHG emissions price for the coproduction technologies in Table 12.27 and stand-alone power options – assuming a US$90/bbl of crude oil price and reference case coal and natural gas pricing (US$2.04/GJ and US$5.1/GJ, respectively). (See Table 12.6 , note (b) for fi nancial parameter assumptions.) Source: based on Liu et al., 2011b .


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The key for developing countries is to lay a sound foundation for fur-ther evolution to low carbon energy systems. In high economic growth developing countries like China and India, reducing conventional pollu-tion is still the most urgent energy challenge. The priority of economic development of these societies tends to lead to increasing emissions of CO 2 . Accordingly, carbon emissions for such countries will increase in the near term as they complete their industrialization and will subse-quently decrease under appropriate sustainable development policies. In the poorest developing countries, economic poverty and associated lack of access to modern forms of energy are the major problems, and growing conventional pollution is a risk as these countries develop. In order to minimize overall carbon emissions from the use of fossil fuels in developing countries, efforts should concentrate on building manu-facturing and infrastructure for the most efficient use of hydrocarbon energy resources and flexibility for incorporation of low carbon energy and feedstocks into the energy mix. Technology leapfrogging in energy-using technologies is another essential component of radical transform-ation strategies.

Although industrialized countries have made major advances in con-trolling conventional pollution, much more needs to be done in this regard—especially for old coal power plants. Moreover, their energy systems have not been designed for minimal CO 2 emissions. At the same time, the energy infrastructure is well established and much of

it is several decades old and ready for replacement or upgrade. Thus, the emphasis going forward in industrialized countries should be on replacing or upgrading obsolete infrastructure, e.g., via repowering sites of old fossil fuel power plants with technologies offering additional cap-abilities (such as coproduction of electricity and fuels, as discussed in this chapter) and pursuing CCS retrofits.

While different strategies are needed regionally, this chapter has iden-tified four key technology-related requirements as essential for trans-forming the fossil energy landscape: (i) continued enhancement of energy conversion efficiencies, (ii) carbon capture and storage (CCS), (iii) co-utilization of fossil fuel and biomass in the same facilities, and (iv) coproduction of multiple energy carriers at the same facilities.

Fossil fuel/biomass coprocessing with CCS to coproduce clean liquid fuels and electricity with low greenhouse gas emissions is a technically and economically feasible strategy that can make significant contribu-tions in addressing all the major challenges posed by present energy systems, although additional strategies are also needed to solve all the problems posed by fossil fuels in the electric power and transporta-tion sectors. Moreover, coproduction via fossil fuel/biomass coprocess-ing with CCS also represents a promising approach for launching CCS technologies in the market early on (facilitating as a result of early experience CCS for power-only systems in both greenfield and brown-field applications). Also, it offers a promising route for gaining early experience using lignocellulosic biomass to make liquid fuels thermo-chemically at attractive costs. And it can serve as a bridge to enab-ling CCS as a routine activity for biomass energy (with corresponding negative greenhouse gas emissions) in the post-2030 era. The latter could plausibly become a major industrial development opportunity for economically poor and fossil fuel-poor but biomass-rich regions, while making major contributions to decarbonization of the transport sector worldwide.

No technological breakthroughs are needed to get started with coproduction technologies and strategies that involve fossil fuel/bio-mass coprocessing with CCS. Most of the technical challenges are engin-eering issues best addressed via commercial-scale experience (learning by doing).

Despite the multiple attractions of coproduction systems, the concept faces formidable institutional hurdles because of complexities at the systems level. Success requires managing two disparate feedstocks (a fossil fuel and biomass) to provide simultaneously three commodity products (liquid fuels, electricity, and CO 2 ) that would serve three very different markets.

With fossil fuel/biomass coproduction systems, fossil fuel consumers for power generation would have to become consumers of biomass as well. There has been some experience cofiring existing coal power plants with biomass but that has been at biomass levels far more modest than the levels envisioned for the coproduction technologies described here.

Table 12.28 | Thought experiments with zero GHG emissions for global transportation in 2050.

Global C/B TE

Global G/B TE

Decarbonized synfuels produced for transportation in 2050, EJ/yr LHV

59.8 59.0

FTL via coproduction, % 32.7 29.8

FTL via BTL-RC-CCS, % 67.3 70.2

Decarbonized net electricity generation in 2050, million MWh/yr

3,484 3,621

Crude oil-derived products used in transportation in 2050, EJ/yr LHV

45.0 45.2

Fossil fuel feedstock for making FTL in thought experiment, EJ/yr HHV

45.7 36.3

Biomass for making FTL in thought experiment, EJ/yr HHV (a) 111.7 114.4

Fossil fuel feedstock (coal or NG) needed for Modifi ed Blue Map Scenario relative to use of that feedstock in IEA Blue Map Scenario in 2050

1.46 1.26

Fossil fuel feedstock (coal or NG) needed for Modifi ed Blue Map Scenario relative to use of that feedstock in IEA Baseline Scenario in 2050

0.38 0.81

Fossil fuel feedstock (coal or NG) needed for Modifi ed Blue Map Scenario relative to use of that feedstock in 2005

1.15 1.59

Overall GHG emissions avoided in displacing conventional energy, GtCO 2 -eq/yr

12.8 12.6

CO 2 storage rate, GtCO 2 /yr 8.47 6.75

a Estimates of sustainable biomass resource potentials are subject to discussion (e.g., see Chapters 7 , 20 ).


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Moreover, there is little reason to expect that electricity generators will want to take on the risks of producing and marketing liquid fuels. The oil industry, which could do that, has shown little interest in producing either synfuels from coal or electricity for sale to the electric grid, which offers much lower profit margins than what the oil industry has been accustomed to in exploration and production (E & P).

Yet these obstacles might be surmountable. Coal power generators are coming to realize they will have to embrace CCS in order to survive in a carbon-constrained world and will have to give priority in industrialized countries to CCS for existing coal power plant sites. Coal suppliers who are eager to see coal use expand into synfuels production are coming to realize that this cannot be done without both CCS and coprocessing of biomass under a stringent carbon policy constraint. Biomass suppli-ers might become interested in the concept once they recognize the potential for greater profits selling biomass to operators of such systems rather than to producers of “pure” biofuels, such as cellulosic ethanol. The coproduction concepts described in this chapter offer the potential for meeting these obligations in a more profitable manner than other routes. And some multinational oil companies might come to embrace synfuels production both because they are running out of E & P invest-ment opportunities as a result of being denied adequate access to the oil resources controlled by national oil companies, and because at high oil and GHG emissions prices, profit margins with coproduction systems can approach historical norms for E & P investments.

Strategic corporate alliances involving partnerships across industries could facilitate deployment of coproduction systems. Encouraging power industry/oil industry partnerships is likely to be especially important. Power companies could, of course, manage the power side of the business but may be uncomfortable with gasification tech-nology − which doesn’t resemble the “boiler technology” that they are accustomed to managing. Moreover, the power industry has no experience with either CO 2 capture or management of the geological structures needed for CO 2 storage. The oil industry could, of course, manage liquid fuels production and marketing quite well. It has exten-sive experience with CO 2 capture (at refineries and chemical process plants for purposes unrelated to CO 2 storage), with CO 2 transport (for enhanced oil recovery), with management of geological structures similar to those that will be used for CO 2 storage, and with gasification of petroleum residuals at both refineries and chemical process plants that could facilitate their becoming comfortable with coal and bio-mass gasification. Moreover, oil companies that also sell natural gas might become interested in natural gas/biomass coprocessing systems that make fuels and electricity with CCS.

12.8.2 New Policies for a Radical Transformation

A radical transformation of the fossil energy landscape is unlikely to occur without new facilitating public policies. Needed critical broad cross-cutting policies include:

Carbon mitigation policies in the near term for which implicit GHG •emission prices are high enough to make CCS competitive as a routine commercial activity, and which are implemented soon in the context of the expressed G8 support for a global effort to limit the increase in average global temperature due to climate change to 2°C above the pre-industrial level. This goal is written into the Copenhagen Accord and reconfirmed during COP16 in Cancun. The G8 statement in July 2009 noted that this formidable goal will require a global reduction in emissions by at least 50% by 2050 (relative to the 1990 level), and they supported the goal for industrialized countries to achieve 80% reductions by 2050 to help meet the global 50% reduction.

New air pollution control policies are needed, with highest priority •given to pollution from existing coal power plants in industrialized countries and indoor air pollution in developing countries. The ana-lysis in Chapter 12 shows the value of crafting new air pollution control policies and GHG mitigation policies together because of the helpful synergisms that would arise with “co-control” approaches.

Technological innovation policies in support of the plausible radical •transformation described in this chapter should include both support for R&D on promising technological options and incentives for early deployment, including incentives that would encourage needed new inter-industry partnerships. First-of-a-kind projects are always risky, both technologically and financially. Despite the attractive economic features of coprocessing, coproduction, and other technologies dis-cussed in this chapter, without incentives for first-of-a-kind and early deployment projects that offer major public benefits, such technolo-gies will enter the market only slowly or not at all.

High priority should be given to encouraging early CCS action, espe-cially for coal, because if coal is to be widely used in a future carbon- constrained world (via coproduction and coprocessing with biomass or via any other means), so doing will be viable only if the option is avail-able to safely store CO 2 in geological media. For geologic storage, there appear to be neither technical issues that cannot be managed nor eco-nomic show-stoppers (see Chapter 13 ). Nevertheless, there is a pressing need to carry out a significant number of integrated commercial-scale CCS projects worldwide (each involving the annual storage of at least one MtCO 2 /yr) with an emphasis on storage in deep saline formations, to: (i) address scientific and engineering issues at scale for storage; (ii) provide a sound empirical basis for developing the regulatory and pol-itical framework for site selection, permitting, operation, monitoring, and closure of storage sites for routine commercial CCS projects; and (iii) satisfy a wide range of stakeholders as to the viability of CCS as a “gigascale” carbon mitigation option.

The international political framework for early CCS action has already been established. As noted earlier, the G8 Summit in 2008 produced an agreement to sponsor at least twenty commercial-scale, fully inte-grated CCS demonstration projects worldwide that would be committed by 2010 with the aim of establishing the basis for broad commercial


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deployment of CCS technologies after 2020. The G8 reiterated its call for these CCS projects in 2009 . In August 2010, a high-level task force in the U.S. created by President Obama issued its report on a comprehen-sive CCS strategy for the United States that includes bringing five to ten commercial demonstration projects online by 2016.

Much if not all of the incremental cost of CCS for the 20 projects called for by the G8 will probably have to be paid for by governments (indi-vidually or collectively). It is likely that carbon prices will be lower ini-tially than what will be needed to make pursuit of CCS a profitable activity for private companies in many, if not most, parts of the world. To minimize spending, governments should aim to pursue projects in which they can maximize the learning about the gigascale prospects of CCS per dollar spent. In this context, the coproduction systems described in this chapter are good candidates for CCS early action projects because they have much lower capture costs than power only systems. If these projects are allowed to compete for government awards for CCS dem-onstrations, the cost to government might be significantly less than for CCS demonstration projects based on power-only systems. Accordingly, coproduction facilities coprocessing fossil fuel and biomass with CCS, especially those built in coal-rich countries, should be considered ser-iously as candidates for some of the needed CCS early action projects and supported financially jointly by the governments of several coal-intensive energy economies.

Since it will require at least a decade of demonstration efforts before CCS systems can begin to be routinely deployed, the deployment of CCS systems in conjunction with fossil energy conversion would need to pro-ceed very rapidly thereafter to achieve deep reductions in global GHG emissions from fossil fuel burning by 2050.

Analysis in this chapter indicates that biomass conversion with CCS could play an essential role in enabling continued fossil fuel use. This would be accomplished by off-setting GHG emissions from fossil fuels via the strongly negative emissions of biomass/CCS systems. Two new initiatives needed in this area are:

New policies should encourage demonstration and commercial- •ization of large biomass gasifiers (300–600 MW biomass input) because these represent a key technology for economically attractive biomass/CCS systems. To date, biomass gasifiers have only been suc-cessfully demonstrated at the scale of tens of MW biomass input.

Detailed assessments should be carried out of the prospects for •biomass production for energy on a sustainable basis in ways that minimize conflicts with food production, adverse indirect land-use impacts, and biodiversity. Emphasis should be on agricultural

residues, forest residues (including mill residues, logging residues, diseased tree removals, fuel treatment thinnings, and productivity enhancement thinnings), and the growing of dedicated energy crops on abandoned cropland and other degraded lands. These assess-ments should be carried out in each of the major world regions.

New policies are also needed to promote universal access to clean cook-ing fuels (as discussed in detail in Chapter 19 , Section 19.2.2 ) derived from coal and/or biomass systems with CCS ( Section 12.5 ):

As a basis for new policy, CO • 2 storage assessments should be car-ried out in each of the major regions requiring clean cooking fuels − with financial support from the international community. CO 2 stor-age prospects are not well known in countries where clean cooking fuels are sorely needed. This is especially true in biomass-rich but coal-poor regions − where consideration of CCS as a carbon mitiga-tion option has probably not been given much thought. Accordingly, “bottom-up” assessments of storage prospects, including the con-struction of supply curves (storage capacity in tonnes vs cost in US$/t), are needed on a reservoir-by-reservoir basis.

For regions where there are good prospects for biomass energy with •CCS, official development assistance should be expanded to help develop the physical infrastructures and human capacities needed to build and manage large industries based on modern biomass con-version technologies with CCS. This additional ODA should aim to establish this industry so that it can take off as GHG emission prices approach levels high enough that market forces are sufficient to sup-port commercial biomass/CCS activities.

Finally, new public policies are needed to facilitate in the near term indus-trial collaborations between companies that would produce simultaneously fuels (clean cooking fuels as well as transportation fuels) and electricity from fossil fuels and biomass in regions having significant supplies of both. It would be desirable to identify policy instruments that specify perform-ance rather than technology and maximize use of market forces in meet-ing performance goals. Promising approaches along these lines include: (i) mandating a Low Carbon Standard for Fuels (Andress et al., 2010 ; Sperling and Yeh, 2010 ), (ii) a low carbon standard for electricity generation, per-haps modeled after Renewable Portfolio Standards or green certificate markets; (iii) feed-in tariffs for environmentally-qualified electricity, and (iv) a Universal Clean Cooking Fuel Standard in regions requiring major infusions of clean cooking fuels, perhaps modeled after the “obligation to serve” mandates of the rural electrification programs introduced in the United States in the 1930s. The latter could plausibly facilitate the forma-tion of strategic industrial alliances that would be capable of guaranteeing universal access to clean cooking fuels without major subsidy.


988

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